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2018-12-31 C000388 0-38 2018-01-01 2018-12-31 C000388 4-35 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-40 2018-01-01 2018-12-31 C000388 7-22 2018-12-31 C000388 0-47 2018-01-01 2018-12-31 C000388 1-25 2018-01-01 2018-12-31 C000388 0-13 2018-01-01 2018-12-31 C000388 35-14 2018-01-01 2018-12-31 C000388 14-11 2018-01-01 2018-12-31 C000388 0-23 2018-01-01 2018-12-31 C000388 4-32 2018-12-31 C000388 4-6 2018-01-01 2018-12-31 C000388 18-11 2018-01-01 2018-12-31 C000388 21-22 2018-01-01 2018-12-31 C000388 16-27 2018-12-31 C000388 2-13 2018-12-31 C000388 0-35 2018-01-01 2018-12-31 C000388 8-12 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 0-39 2018-01-01 2018-12-31 C000388 12-8 2018-01-01 2018-12-31 C000388 34-16 2018-01-01 2018-12-31 C000388 34-2 2018-01-01 2018-12-31 C000388 13-9 2018-01-01 2018-12-31 C000388 12-34 2018-12-31 C000388 1-24 2018-01-01 2018-12-31 C000388 3-16 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-37 2018-01-01 2018-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 4-8 2018-01-01 2018-12-31 C000388 0-31 2018-01-01 2018-12-31 C000388 12-20 2018-01-01 2018-12-31 C000388 7-11 2018-01-01 2018-12-31 C000388 ferc:OtherUtilityMember 0-17 2018-12-31 C000388 5-20 2018-01-01 2018-12-31 C000388 27-17 2018-01-01 2018-12-31 C000388 0-13 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 4-37 2018-12-31 C000388 ferc:ElectricUtilityMember 3-12 2018-01-01 2018-12-31 C000388 0-19 2018-01-01 2018-12-31 C000388 25-31 2018-01-01 2018-12-31 C000388 26-6 2018-01-01 2018-12-31 C000388 17-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-37 2018-12-31 C000388 ferc:ElectricUtilityMember 1-21 2018-01-01 2018-12-31 C000388 6-7 2018-01-01 2018-12-31 C000388 0-16 2018-01-01 2018-12-31 C000388 19-7 2018-01-01 2018-12-31 C000388 1-20 2018-01-01 2018-12-31 C000388 0-24 2018-12-31 C000388 24-34 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-03-31 C000388 ferc:ElectricUtilityMember 5-23 2018-12-31 C000388 0-37 2018-12-31 C000388 11-10 2018-12-31 C000388 22-26 2018-01-01 2018-12-31 C000388 10-25 2018-12-31 C000388 13-27 2018-01-01 2018-12-31 C000388 0-22 2018-12-31 C000388 15-1 2018-01-01 2018-12-31 C000388 33-33 2018-01-01 2018-12-31 C000388 39-28 2018-01-01 2018-12-31 C000388 11-21 2018-01-01 2018-12-31 C000388 2-10 2018-01-01 2018-12-31 C000388 2-9 2018-01-01 2018-12-31 C000388 30-9 2018-01-01 2018-12-31 C000388 3-20 2018-12-31 C000388 11-5 2018-12-31 C000388 36-15 2018-01-01 2018-12-31 C000388 10-24 2018-01-01 2018-12-31 C000388 4-17 2018-01-01 2018-12-31 C000388 ferc:GasUtilityMember 0-10 2018-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 27-4 2018-01-01 2018-12-31 C000388 16-12 2018-12-31 C000388 4-19 2018-01-01 2018-12-31 C000388 1-27 2018-12-31 C000388 ferc:ElectricUtilityMember 4-38 2018-12-31 C000388 0-40 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-11 2018-12-31 C000388 24-5 2018-01-01 2018-12-31 C000388 14-15 2018-01-01 2018-12-31 C000388 7-40 2018-01-01 2018-12-31 C000388 7-23 2018-01-01 2018-12-31 C000388 14-37 2018-01-01 2018-12-31 C000388 0-19 2018-12-31 C000388 5-5 2018-01-01 2018-12-31 C000388 ferc:OtherUtilityOrNonutilityMember 0-11 2018-01-01 2018-12-31 C000388 STANISLAUS-6 2018-01-01 2018-12-31 C000388 1-37 2017-12-31 C000388 22-9 2018-01-01 2018-12-31 C000388 8-14 2018-01-01 2018-12-31 C000388 0-43 2018-01-01 2018-12-31 C000388 1-4 2018-01-01 2018-12-31 C000388 0-1 2018-12-31 C000388 4-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-31 2018-12-31 C000388 14-34 2018-01-01 2018-12-31 C000388 0-35 2018-01-01 2018-12-31 C000388 14-1 2018-01-01 2018-12-31 C000388 13-36 2018-12-31 C000388 1-6 2018-01-01 2018-12-31 C000388 37-31 2018-01-01 2018-12-31 C000388 3-19 2018-01-01 2018-12-31 C000388 1-10 2018-01-01 2018-12-31 C000388 17-5 2018-01-01 2018-12-31 C000388 1-1 2018-01-01 2018-12-31 C000388 2-24 2018-01-01 2018-12-31 C000388 3-19 2018-12-31 C000388 2-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-16 2018-01-01 2018-12-31 C000388 19-32 2018-01-01 2018-12-31 C000388 8-21 2018-12-31 C000388 7-31 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-6 2018-12-31 C000388 ferc:OtherElectricUtilityMember 2017-12-31 C000388 4-12 2018-01-01 2018-12-31 C000388 0-9 2018-01-01 2018-12-31 C000388 1-3 2018-01-01 2018-12-31 C000388 6-3 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-32 2018-01-01 2018-12-31 C000388 24-6 2018-01-01 2018-12-31 C000388 12-39 2018-12-31 C000388 13-33 2018-12-31 C000388 4-41 2018-01-01 2018-12-31 C000388 DUTCH FLAT-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-40 2018-12-31 C000388 1-20 2018-12-31 C000388 14-12 2018-01-01 2018-12-31 C000388 15-13 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 0-31 2018-12-31 C000388 9-30 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-29 2018-12-31 C000388 0-25 2017-01-01 2017-12-31 C000388 5-3 2018-01-01 2018-12-31 C000388 11-1 2018-01-01 2018-12-31 C000388 16-13 2018-12-31 C000388 ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract 2018-01-01 2018-12-31 C000388 1-4 2018-12-31 C000388 12-25 2018-01-01 2018-12-31 C000388 3-6 2018-12-31 C000388 0-20 2017-01-01 2017-12-31 C000388 PIT NO. 7-5 2018-01-01 2018-12-31 C000388 18-24 2018-01-01 2018-12-31 C000388 2-14 2018-01-01 2018-12-31 C000388 1-12 2018-01-01 2018-12-31 C000388 1-28 2018-01-01 2018-12-31 C000388 0-13 2018-12-31 C000388 7-26 2018-01-01 2018-12-31 C000388 5-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-24 2018-01-01 2018-12-31 C000388 36-31 2018-01-01 2018-12-31 C000388 4-12 2018-01-01 2018-12-31 C000388 13-7 2018-12-31 C000388 1-12 2018-12-31 C000388 17-9 2018-01-01 2018-12-31 C000388 2-21 2018-12-31 C000388 5-34 2018-12-31 C000388 ferc:ElectricUtilityMember 1-19 2018-01-01 2018-12-31 C000388 16-8 2018-01-01 2018-12-31 C000388 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2018-12-31 C000388 2-30 2018-01-01 2018-12-31 C000388 1-11 2018-01-01 2018-12-31 C000388 17-25 2018-12-31 C000388 1-10 2018-01-01 2018-12-31 C000388 1-8 2018-01-01 2018-12-31 C000388 0-37 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-29 2018-01-01 2018-12-31 C000388 16-24 2018-01-01 2018-12-31 C000388 3-16 2018-01-01 2018-12-31 C000388 27-28 2018-01-01 2018-12-31 C000388 9-2 2018-12-31 C000388 2-13 2018-01-01 2018-12-31 C000388 2-15 2018-01-01 2018-12-31 C000388 7-41 2018-01-01 2018-12-31 C000388 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2017-12-31 C000388 ferc:ElectricUtilityMember 2-24 2018-12-31 C000388 7-16 2018-12-31 C000388 1-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-8 2018-01-01 2018-12-31 C000388 21-31 2018-01-01 2018-12-31 C000388 8-10 2018-12-31 C000388 ferc:DistributionPlantMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C000388 16-16 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 3-32 2018-01-01 2018-12-31 C000388 10-30 2018-01-01 2018-12-31 C000388 ferc:SulfurDioxideMember 2017-12-31 C000388 21-24 2018-01-01 2018-12-31 C000388 10-20 2018-12-31 C000388 4-5 2018-01-01 2018-12-31 C000388 28-1 2018-01-01 2018-12-31 C000388 7-4 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-10 2018-01-01 2018-12-31 C000388 2-8 2018-01-01 2018-12-31 C000388 Gateway Gen Station-0 2018-01-01 2018-12-31 C000388 18-34 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 6-16 2018-01-01 2018-12-31 C000388 0-11 2018-12-31 C000388 32-29 2018-01-01 2018-12-31 C000388 5-25 2018-01-01 2018-12-31 C000388 14-1 2018-01-01 2018-12-31 C000388 5-22 2018-01-01 2018-12-31 C000388 1-14 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 19-9 2018-01-01 2018-12-31 C000388 0-41 2018-01-01 2018-12-31 C000388 0-31 2018-12-31 C000388 15-2 2018-01-01 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-16 2018-12-31 C000388 10-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-2 2018-01-01 2018-12-31 C000388 34-34 2018-01-01 2018-12-31 C000388 1-23 2018-12-31 C000388 17-7 2018-01-01 2018-12-31 C000388 1-8 2017-12-31 C000388 12-15 2018-01-01 2018-12-31 C000388 5-28 2018-01-01 2018-12-31 C000388 0-9 2018-01-01 2018-12-31 C000388 0-3 2018-12-31 C000388 4-30 2017-12-31 C000388 2-21 2018-01-01 2018-12-31 C000388 4-22 2018-01-01 2018-12-31 C000388 9-12 2018-01-01 2018-12-31 C000388 2-34 2018-12-31 C000388 1-14 2018-01-01 2018-12-31 C000388 4-21 2018-01-01 2018-12-31 C000388 0-32 2018-01-01 2018-12-31 C000388 2-10 2018-01-01 2018-12-31 C000388 20-35 2018-01-01 2018-12-31 C000388 26-8 2018-01-01 2018-12-31 C000388 5-6 2018-01-01 2018-12-31 C000388 3-12 2018-01-01 2018-12-31 C000388 5-9 2018-01-01 2018-12-31 C000388 0-30 2018-01-01 2018-12-31 C000388 0-34 2018-01-01 2018-12-31 C000388 9-26 2018-01-01 2018-12-31 C000388 5-1 2018-01-01 2018-12-31 C000388 1-10 2018-01-01 2018-12-31 C000388 33-24 2018-01-01 2018-12-31 C000388 0-30 2018-01-01 2018-12-31 C000388 24-17 2018-01-01 2018-12-31 C000388 2-34 2018-12-31 C000388 7-12 2018-01-01 2018-12-31 C000388 4 2018-01-01 2018-12-31 C000388 0-10 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-27 2018-01-01 2018-12-31 C000388 14-17 2018-01-01 2018-12-31 C000388 31-35 2018-01-01 2018-12-31 C000388 13-26 2018-01-01 2018-12-31 C000388 3-32 2018-01-01 2018-12-31 C000388 3-15 2018-01-01 2018-12-31 C000388 0-4 2018-01-01 2018-12-31 C000388 28-34 2018-01-01 2018-12-31 C000388 1-34 2018-01-01 2018-12-31 C000388 37-33 2018-01-01 2018-12-31 C000388 0-22 2018-01-01 2018-12-31 C000388 32-33 2018-01-01 2018-12-31 C000388 12-21 2018-12-31 C000388 ferc:ElectricUtilityMember 3-34 2018-12-31 C000388 7-42 2018-01-01 2018-12-31 C000388 7-19 2018-12-31 C000388 15-4 2018-01-01 2018-12-31 C000388 2-10 2018-01-01 2018-12-31 C000388 1-6 2018-12-31 C000388 4-3 2018-01-01 2018-12-31 C000388 3-31 2018-12-31 C000388 4-38 2018-01-01 2018-12-31 C000388 4-27 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-22 2018-12-31 C000388 5-34 2018-01-01 2018-12-31 C000388 7-4 2018-01-01 2018-12-31 C000388 17-32 2018-01-01 2018-12-31 C000388 0-31 2017-12-31 C000388 1-16 2018-01-01 2018-12-31 C000388 35-23 2018-01-01 2018-12-31 C000388 1-21 2018-01-01 2018-12-31 C000388 27-19 2018-01-01 2018-12-31 C000388 28-3 2018-01-01 2018-12-31 C000388 24-5 2018-01-01 2018-12-31 C000388 9-33 2018-12-31 C000388 7-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-28 2018-12-31 C000388 19-11 2018-01-01 2018-12-31 C000388 Gas-0 Gateway Gen Station-0 2018-01-01 2018-12-31 C000388 9-8 2018-01-01 2018-12-31 C000388 1-32 2018-12-31 C000388 ferc:ElectricUtilityMember 0-5 2017-12-31 C000388 13-22 2018-01-01 2018-12-31 C000388 37-19 2018-01-01 2018-12-31 C000388 19-21 2018-01-01 2018-12-31 C000388 14-6 2018-01-01 2018-12-31 C000388 13-3 2018-01-01 2018-12-31 C000388 29-18 2018-01-01 2018-12-31 C000388 2-24 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 15-27 2018-12-31 C000388 1-39 2018-01-01 2018-12-31 C000388 1-12 2018-01-01 2018-12-31 C000388 1-18 2018-01-01 2018-12-31 C000388 2-19 2018-01-01 2018-12-31 C000388 0-15 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-19 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-6 2018-01-01 2018-12-31 C000388 27-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 8-1 2018-12-31 C000388 14-28 2018-01-01 2018-12-31 C000388 24-24 2018-01-01 2018-12-31 C000388 5-31 2018-01-01 2018-12-31 C000388 0-11 2018-12-31 C000388 ferc:ElectricUtilityMember 0-8 2018-12-31 C000388 ferc:ElectricOtherFacilitiesMember 0-6 2017-12-31 C000388 ferc:ElectricUtilityMember 7-39 2018-12-31 C000388 2-21 2018-01-01 2018-12-31 C000388 8-10 2018-01-01 2018-12-31 C000388 6-2 2018-12-31 C000388 4-35 2018-01-01 2018-12-31 C000388 16-12 2018-01-01 2018-12-31 C000388 ferc:OperatingUtilityMember 2018-12-31 C000388 23-3 2018-01-01 2018-12-31 C000388 19-26 2018-01-01 2018-12-31 C000388 16-25 2018-01-01 2018-12-31 C000388 19-18 2018-01-01 2018-12-31 C000388 40-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-28 2018-01-01 2018-12-31 C000388 3-1 2018-01-01 2018-12-31 C000388 2-31 2018-01-01 2018-12-31 C000388 1-9 2018-01-01 2018-12-31 C000388 0-33 2018-01-01 2018-12-31 C000388 15-22 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 7-31 2018-12-31 C000388 12-15 2018-12-31 C000388 ferc:ElectricUtilityMember 7-30 2018-12-31 C000388 4-39 2018-01-01 2018-12-31 C000388 0-2 2017-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 6-7 2018-12-31 C000388 2-3 2018-01-01 2018-12-31 C000388 17-13 2018-01-01 2018-12-31 C000388 26-10 2018-01-01 2018-12-31 C000388 1-6 2018-12-31 C000388 16-5 2018-01-01 2018-12-31 C000388 1-12 2017-12-31 C000388 1-33 2017-12-31 C000388 9-28 2018-01-01 2018-12-31 C000388 26-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-41 2018-01-01 2018-12-31 C000388 6-20 2018-12-31 C000388 37-16 2018-01-01 2018-12-31 C000388 ferc:JuneMember PACIFIC GAS AND ELECTRIC COMPANY-0 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-13 2018-12-31 C000388 0-17 2018-01-01 2018-12-31 C000388 0-2 2018-12-31 C000388 0-8 2018-01-01 2018-12-31 C000388 1-38 2018-01-01 2018-12-31 C000388 3-31 2018-01-01 2018-12-31 C000388 COLEMAN-1 2018-01-01 2018-12-31 C000388 9-36 2018-12-31 C000388 ferc:ElectricUtilityMember 4-36 2018-12-31 C000388 1-27 2018-01-01 2018-12-31 C000388 10-15 2018-01-01 2018-12-31 C000388 3-38 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-3 2018-12-31 C000388 0-13 2017-12-31 C000388 3-1 2018-01-01 2018-12-31 C000388 9-31 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-30 2018-12-31 C000388 16-14 2018-12-31 C000388 14-6 2018-01-01 2018-12-31 C000388 29-5 2018-01-01 2018-12-31 C000388 4-28 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-30 2018-12-31 C000388 23-2 2018-01-01 2018-12-31 C000388 4-34 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31-30 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-41 2018-01-01 2018-12-31 C000388 0-31 2018-01-01 2018-12-31 C000388 16-17 2018-01-01 2018-12-31 C000388 10-20 2018-01-01 2018-12-31 C000388 0-35 2018-12-31 C000388 2-9 2018-01-01 2018-12-31 C000388 37-7 2018-01-01 2018-12-31 C000388 10-13 2018-12-31 C000388 16-3 2018-01-01 2018-12-31 C000388 0-6 2018-01-01 2018-12-31 C000388 17-27 2018-01-01 2018-12-31 C000388 1-3 2018-12-31 C000388 13-22 2018-12-31 C000388 2-12 2018-01-01 2018-12-31 C000388 0-3 2018-12-31 C000388 0-5 2018-01-01 2018-12-31 C000388 23-9 2018-01-01 2018-12-31 C000388 0-33 2018-01-01 2018-12-31 C000388 17-24 2018-01-01 2018-12-31 C000388 17-22 2018-01-01 2018-12-31 C000388 3-30 2018-01-01 2018-12-31 C000388 35-31 2018-01-01 2018-12-31 C000388 1-33 2018-01-01 2018-12-31 C000388 9-15 2018-01-01 2018-12-31 C000388 20-11 2018-01-01 2018-12-31 C000388 3-36 2018-01-01 2018-12-31 C000388 17-8 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 0-31 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C000388 BALCH NO. 2-0 2018-01-01 2018-12-31 C000388 27-14 2018-01-01 2018-12-31 C000388 1-27 2018-12-31 C000388 25-20 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-24 2018-12-31 C000388 0-23 2018-12-31 C000388 4-34 2017-12-31 C000388 38-3 2018-01-01 2018-12-31 C000388 35-12 2018-01-01 2018-12-31 C000388 4-24 2018-12-31 C000388 0-19 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-19 2018-12-31 C000388 2-16 2018-01-01 2018-12-31 C000388 1-18 2018-01-01 2018-12-31 C000388 16-11 2018-01-01 2018-12-31 C000388 13-29 2018-01-01 2018-12-31 C000388 20-30 2018-01-01 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 0-27 2018-12-31 C000388 0-20 2018-01-01 2018-12-31 C000388 32-24 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-5 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-34 2018-12-31 C000388 21-35 2018-01-01 2018-12-31 C000388 8-3 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-13 2018-01-01 2018-12-31 C000388 0-27 2017-12-31 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2018-12-31 C000388 9-13 2018-01-01 2018-12-31 C000388 20-17 2018-01-01 2018-12-31 C000388 4-32 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-20 2018-01-01 2018-12-31 C000388 30-2 2018-01-01 2018-12-31 C000388 17-13 2018-01-01 2018-12-31 C000388 6-19 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-11 2018-12-31 C000388 30-23 2018-01-01 2018-12-31 C000388 0-11 2018-01-01 2018-12-31 C000388 0-23 2018-01-01 2018-12-31 C000388 37-23 2018-01-01 2018-12-31 C000388 0-24 2018-01-01 2018-12-31 C000388 7-15 2018-01-01 2018-12-31 C000388 12-12 2018-01-01 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 9-1 2018-12-31 C000388 ferc:ElectricUtilityMember 4-8 2018-01-01 2018-12-31 C000388 4-31 2018-01-01 2018-12-31 C000388 12-37 2018-01-01 2018-12-31 C000388 1-49 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-35 2018-01-01 2018-12-31 C000388 7-9 2018-12-31 C000388 0-10 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-2 2018-01-01 2018-12-31 C000388 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6-28 2018-12-31 C000388 36-14 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-19 2018-12-31 C000388 ferc:ElectricUtilityMember 6-32 2018-01-01 2018-12-31 C000388 0-26 2018-01-01 2018-12-31 C000388 38-10 2018-01-01 2018-12-31 C000388 15-40 2018-12-31 C000388 32-22 2018-01-01 2018-12-31 C000388 10-32 2018-01-01 2018-12-31 C000388 11-2 2018-01-01 2018-12-31 C000388 0-11 2018-12-31 C000388 6-26 2018-01-01 2018-12-31 C000388 33-31 2018-01-01 2018-12-31 C000388 15-31 2018-12-31 C000388 27-21 2018-01-01 2018-12-31 C000388 3-39 2018-01-01 2018-12-31 C000388 12-33 2018-01-01 2018-12-31 C000388 15-22 2018-12-31 C000388 ScheduleInformationOnFormulaRatesAbstract 2018-01-01 2018-12-31 C000388 17-30 2018-01-01 2018-12-31 C000388 25-29 2018-01-01 2018-12-31 C000388 38-13 2018-01-01 2018-12-31 C000388 WISE NO. 1-7 2018-01-01 2018-12-31 C000388 ferc:OtherUtilityOrNonutilityMember 0-11 2018-12-31 C000388 0-11 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-33 2018-12-31 C000388 26-33 2018-01-01 2018-12-31 C000388 18-3 2018-01-01 2018-12-31 C000388 11-24 2018-12-31 C000388 0-26 2018-01-01 2018-12-31 C000388 1-15 2018-01-01 2018-12-31 C000388 14-2 2018-12-31 C000388 0-9 2017-12-31 C000388 ferc:ElectricUtilityMember 1-38 2018-12-31 C000388 15-11 2018-12-31 C000388 0-7 2018-12-31 C000388 0-12 2018-12-31 C000388 3-30 2018-12-31 C000388 9-6 2018-01-01 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 2-28 2018-12-31 C000388 15-6 2018-01-01 2018-12-31 C000388 10-11 2018-01-01 2018-12-31 C000388 26-23 2018-01-01 2018-12-31 C000388 7-12 2018-01-01 2018-12-31 C000388 0-43 2018-01-01 2018-12-31 C000388 16-19 2018-12-31 C000388 34-4 2018-01-01 2018-12-31 C000388 17-25 2018-01-01 2018-12-31 C000388 1-33 2018-01-01 2018-12-31 C000388 0-33 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-36 2018-12-31 C000388 0-16 2018-01-01 2018-09-30 C000388 1-24 2017-12-31 C000388 1-2 2018-12-31 C000388 2-3 2018-01-01 2018-12-31 C000388 1-32 2018-01-01 2018-12-31 C000388 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C000388 ferc:ElectricUtilityMember 4-3 2018-01-01 2018-12-31 C000388 0-30 2018-12-31 C000388 ferc:ElectricUtilityMember 2-38 2018-12-31 C000388 14-30 2018-12-31 C000388 1-16 2018-01-01 2018-12-31 C000388 3-26 2018-01-01 2018-12-31 C000388 8-33 2018-12-31 C000388 ferc:ElectricUtilityMember 1-7 2018-12-31 C000388 1-10 2018-01-01 2018-12-31 C000388 9-5 2018-01-01 2018-12-31 C000388 25-27 2018-01-01 2018-12-31 C000388 15-8 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 12-29 2018-01-01 2018-12-31 C000388 1-9 2017-12-31 C000388 ferc:ElectricUtilityMember 2-32 2018-12-31 C000388 5-26 2018-12-31 C000388 34-20 2018-01-01 2018-12-31 C000388 5-30 2018-12-31 C000388 3-31 2018-12-31 C000388 24-29 2018-01-01 2018-12-31 C000388 39-3 2018-01-01 2018-12-31 C000388 30-31 2018-01-01 2018-12-31 C000388 18-13 2018-01-01 2018-12-31 C000388 4-22 2017-12-31 C000388 12-19 2018-12-31 C000388 8-23 2018-01-01 2018-12-31 C000388 0-23 2018-12-31 C000388 0-1 2018-12-31 C000388 0-12 2018-01-01 2018-12-31 C000388 15-26 2018-12-31 C000388 34-9 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-38 2018-01-01 2018-12-31 C000388 1-16 2018-01-01 2018-12-31 C000388 41-8 2018-01-01 2018-12-31 C000388 2-20 2018-01-01 2018-12-31 C000388 6-9 2018-01-01 2018-12-31 C000388 0-10 2018-01-01 2018-12-31 C000388 11-13 2018-12-31 C000388 14-12 2018-12-31 C000388 ferc:ElectricUtilityMember 3-3 2018-01-01 2018-12-31 C000388 0-35 2018-12-31 C000388 3-15 2018-12-31 C000388 15-16 2018-01-01 2018-12-31 C000388 1-14 2018-01-01 2018-12-31 C000388 5-13 2018-01-01 2018-12-31 C000388 13-40 2018-12-31 C000388 ferc:ElectricUtilityMember 4-24 2018-12-31 C000388 14-5 2018-01-01 2018-12-31 C000388 26-11 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-23 2018-12-31 C000388 ferc:ElectricUtilityMember 5-5 2018-01-01 2018-12-31 C000388 0-12 2018-01-01 2018-06-30 C000388 ferc:ElectricUtilityMember 0-9 2018-12-31 C000388 ferc:ElectricUtilityMember 5-35 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 3-31 2017-12-31 C000388 26-4 2018-01-01 2018-12-31 C000388 2-22 2018-01-01 2018-12-31 C000388 DRUM NO. 1-2 2018-01-01 2018-12-31 C000388 31-32 2018-01-01 2018-12-31 C000388 36-16 2018-01-01 2018-12-31 C000388 3-14 2018-12-31 C000388 37-25 2018-01-01 2018-12-31 C000388 9-16 2018-12-31 C000388 0-27 2018-12-31 C000388 4-4 2018-01-01 2018-12-31 C000388 1-5 2018-01-01 2018-12-31 C000388 0-12 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-4 2018-12-31 C000388 ferc:NovemberMember PACFIC GAS AND ELECTRIC COMPANY-0 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-42 2018-01-01 2018-12-31 C000388 5-32 2018-01-01 2018-12-31 C000388 3-17 2018-01-01 2018-12-31 C000388 0-49 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-42 2018-12-31 C000388 ferc:ElectricUtilityMember 3-11 2018-12-31 C000388 1-9 2018-01-01 2018-12-31 C000388 16-9 2018-12-31 C000388 23-28 2018-01-01 2018-12-31 C000388 3-16 2018-12-31 C000388 15-24 2018-01-01 2018-12-31 C000388 4-8 2018-01-01 2018-12-31 C000388 2-35 2018-01-01 2018-12-31 C000388 4-18 2018-12-31 C000388 1-7 2017-12-31 C000388 21-11 2018-01-01 2018-12-31 C000388 0-6 2018-01-01 2018-12-31 C000388 0-31 2018-12-31 C000388 5-26 2018-01-01 2018-12-31 C000388 11-5 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-11 2018-01-01 2018-12-31 C000388 3-5 2018-01-01 2018-12-31 C000388 0-9 2018-12-31 C000388 ferc:ElectricUtilityMember 3-6 2018-01-01 2018-12-31 C000388 20-13 2018-01-01 2018-12-31 C000388 15-34 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-3 2018-01-01 2018-12-31 C000388 0-29 2018-12-31 C000388 12-7 2018-01-01 2018-12-31 C000388 13-5 2018-01-01 2018-12-31 C000388 8-13 2018-01-01 2018-12-31 C000388 11-16 2018-01-01 2018-12-31 C000388 2-3 2018-12-31 C000388 1-37 2018-12-31 C000388 14-24 2018-12-31 C000388 10-9 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-40 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-18 2018-01-01 2018-12-31 C000388 4-32 2017-12-31 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C000388 7-27 2018-12-31 C000388 9-7 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-36 2018-01-01 2018-12-31 C000388 36-19 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-34 2018-01-01 2018-12-31 C000388 19-11 2018-01-01 2018-12-31 C000388 0-7 2017-12-31 C000388 12-4 2018-01-01 2018-12-31 C000388 1-31 2018-01-01 2018-12-31 C000388 7-1 2018-01-01 2018-12-31 C000388 25-10 2018-01-01 2018-12-31 C000388 13-32 2018-12-31 C000388 12-23 2018-12-31 C000388 4-10 2017-12-31 C000388 ferc:ElectricUtilityMember 6-29 2018-01-01 2018-12-31 C000388 1-8 2018-12-31 C000388 0-37 2018-01-01 2018-12-31 C000388 7-37 2018-01-01 2018-12-31 C000388 5-20 2018-12-31 C000388 11-3 2018-01-01 2018-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 35-2 2018-01-01 2018-12-31 C000388 12-15 2018-01-01 2018-12-31 C000388 9-23 2018-12-31 C000388 6-33 2018-01-01 2018-12-31 C000388 27-33 2018-01-01 2018-12-31 C000388 0-11 2017-12-31 C000388 2-38 2018-01-01 2018-12-31 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2018-12-31 C000388 22-31 2018-01-01 2018-12-31 C000388 17-5 2018-01-01 2018-12-31 C000388 12-17 2018-01-01 2018-12-31 C000388 10-2 2018-01-01 2018-12-31 C000388 37-21 2018-01-01 2018-12-31 C000388 0-34 2018-01-01 2018-12-31 C000388 23-7 2018-01-01 2018-12-31 C000388 0-13 2018-12-31 C000388 2-26 2018-12-31 C000388 ferc:ElectricUtilityMember 6-7 2018-01-01 2018-12-31 C000388 28-26 2018-01-01 2018-12-31 C000388 14-12 2018-01-01 2018-12-31 C000388 2-8 2018-01-01 2018-12-31 C000388 0-38 2018-01-01 2018-12-31 C000388 0-24 2018-12-31 C000388 28-12 2018-01-01 2018-12-31 C000388 1-4 2018-01-01 2018-12-31 C000388 16-24 2018-01-01 2018-12-31 C000388 2-4 2018-01-01 2018-12-31 C000388 0-40 2018-12-31 C000388 22-12 2018-01-01 2018-12-31 C000388 6-38 2018-01-01 2018-12-31 C000388 31-24 2018-01-01 2018-12-31 C000388 3-39 2018-12-31 C000388 0-19 2018-01-01 2018-03-31 C000388 7-36 2018-12-31 C000388 ferc:ElectricUtilityMember 2-8 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 25-28 2018-01-01 2018-12-31 C000388 13-11 2018-01-01 2018-12-31 C000388 0-16 2018-01-01 2018-12-31 C000388 0-41 2018-01-01 2018-12-31 C000388 40-8 2018-01-01 2018-12-31 C000388 16-32 2018-12-31 C000388 17-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-37 2018-12-31 C000388 ferc:ElectricUtilityMember 4-9 2018-01-01 2018-12-31 C000388 14-32 2018-12-31 C000388 5-1 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-1 2018-12-31 C000388 40-35 2018-01-01 2018-12-31 C000388 14-30 2018-01-01 2018-12-31 C000388 18-19 2018-01-01 2018-12-31 C000388 1-25 2018-12-31 C000388 2-22 2018-12-31 C000388 11-28 2018-12-31 C000388 8-21 2018-01-01 2018-12-31 C000388 0-10 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-6 2018-12-31 C000388 1-19 2018-12-31 C000388 15-8 2018-12-31 C000388 25-16 2018-01-01 2018-12-31 C000388 37-3 2018-01-01 2018-12-31 C000388 9-34 2018-01-01 2018-12-31 C000388 29-7 2018-01-01 2018-12-31 C000388 38-12 2018-01-01 2018-12-31 C000388 5-6 2018-12-31 C000388 1-32 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RIVER-4 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-40 2018-12-31 C000388 9-14 2018-01-01 2018-12-31 C000388 14-20 2018-01-01 2018-12-31 C000388 2-15 2018-12-31 C000388 32-35 2018-01-01 2018-12-31 C000388 13-32 2018-01-01 2018-12-31 C000388 5-21 2018-01-01 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 3-34 2018-12-31 C000388 1-6 2018-01-01 2018-12-31 C000388 2-32 2018-01-01 2018-12-31 C000388 25-1 2018-01-01 2018-12-31 C000388 2-2 2018-12-31 C000388 3-33 2017-12-31 C000388 ferc:ElectricUtilityMember 5-9 2018-12-31 C000388 32-28 2018-01-01 2018-12-31 C000388 7-10 2018-12-31 C000388 11-9 2018-01-01 2018-12-31 C000388 3-19 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 17-38 2018-01-01 2018-12-31 C000388 0-17 2018-12-31 C000388 5-39 2018-12-31 C000388 0-7 2018-01-01 2018-09-30 C000388 34-5 2018-01-01 2018-12-31 C000388 5-25 2018-01-01 2018-12-31 C000388 16-21 2018-01-01 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-25 2018-12-31 C000388 2-4 2018-01-01 2018-12-31 C000388 KERCKHOFF NO. 2-4 2018-01-01 2018-12-31 C000388 2-5 2018-12-31 C000388 29-12 2018-01-01 2018-12-31 C000388 0-12 2018-12-31 C000388 2-4 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-32 2018-12-31 C000388 ferc:ElectricUtilityMember ferc:OtherProductionPlantMember 2018-01-01 2018-12-31 C000388 HAAS-3 2018-01-01 2018-12-31 C000388 6-24 2018-12-31 C000388 0-11 2017-12-31 C000388 ferc:SulfurDioxideMember ferc:ThreeYearsMember 2017-12-31 C000388 1-14 2018-12-31 C000388 0-27 2018-01-01 2018-12-31 C000388 2-10 2018-01-01 2018-12-31 C000388 18-35 2018-01-01 2018-12-31 C000388 12-13 2018-01-01 2018-12-31 C000388 4-10 2018-01-01 2018-12-31 C000388 HALSEY-3 2018-01-01 2018-12-31 C000388 0-6 2017-12-31 C000388 0-29 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-12 2018-01-01 2018-12-31 C000388 ferc:OtherUtilityMember 0-17 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 0-18 2018-01-01 2018-12-31 C000388 2-6 2018-01-01 2018-12-31 C000388 1-24 2018-01-01 2018-12-31 C000388 12-9 2018-01-01 2018-12-31 C000388 0-31 2017-12-31 C000388 1-32 2018-01-01 2018-12-31 C000388 3-3 2018-12-31 C000388 2-31 2018-12-31 C000388 5-2 2018-01-01 2018-12-31 C000388 9-2 2018-01-01 2018-12-31 C000388 10-14 2018-01-01 2018-12-31 C000388 0-12 2018-12-31 C000388 2-39 2018-01-01 2018-12-31 C000388 9-40 2018-01-01 2018-12-31 C000388 13-11 2018-01-01 2018-12-31 C000388 8-1 2018-12-31 C000388 36-10 2018-01-01 2018-12-31 C000388 4-15 2018-12-31 C000388 10-8 2018-12-31 C000388 10-29 2018-01-01 2018-12-31 C000388 0-17 2018-01-01 2018-12-31 C000388 39-20 2018-01-01 2018-12-31 C000388 0-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-24 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 4-2 2018-01-01 2018-12-31 C000388 0-7 2018-12-31 C000388 2-22 2018-01-01 2018-12-31 C000388 7-18 2018-01-01 2018-12-31 C000388 5-27 2018-01-01 2018-12-31 C000388 2-43 2018-01-01 2018-12-31 C000388 15-33 2018-12-31 C000388 16-1 2018-01-01 2018-12-31 C000388 24-26 2018-01-01 2018-12-31 C000388 28-4 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-38 2018-01-01 2018-12-31 C000388 16-5 2018-12-31 C000388 16-7 2018-12-31 C000388 27-5 2018-01-01 2018-12-31 C000388 4-37 2018-01-01 2018-12-31 C000388 0-5 2018-01-01 2018-12-31 C000388 5-24 2018-01-01 2018-12-31 C000388 1-25 2017-12-31 C000388 14-4 2018-12-31 C000388 17-35 2018-01-01 2018-12-31 C000388 10-11 2018-01-01 2018-12-31 C000388 1-9 2018-01-01 2018-12-31 C000388 24-10 2018-01-01 2018-12-31 C000388 31-9 2018-01-01 2018-12-31 C000388 0-36 2018-01-01 2018-12-31 C000388 22-28 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-25 2018-01-01 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 0-7 2018-01-01 2018-12-31 C000388 13-2 2018-01-01 2018-12-31 C000388 0-18 2018-01-01 2018-12-31 C000388 14-31 2018-12-31 C000388 24-7 2018-01-01 2018-12-31 C000388 0-16 2018-12-31 C000388 0-9 2018-01-01 2018-12-31 C000388 0-19 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-4 2018-01-01 2018-12-31 C000388 21-2 2018-01-01 2018-12-31 C000388 12-28 2018-12-31 C000388 7-25 2018-01-01 2018-12-31 C000388 13-3 2018-12-31 C000388 15-12 2018-01-01 2018-12-31 C000388 4-22 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-7 2018-12-31 C000388 0-19 2018-01-01 2018-12-31 C000388 2-38 2018-01-01 2018-12-31 C000388 9-5 2018-01-01 2018-12-31 C000388 0-12 2018-01-01 2018-12-31 C000388 0-6 2018-01-01 2018-12-31 C000388 35-17 2018-01-01 2018-12-31 C000388 0-22 2018-01-01 2018-06-30 C000388 6-22 2018-12-31 C000388 ferc:ElectricUtilityMember 6-23 2018-01-01 2018-12-31 C000388 14-33 2018-01-01 2018-12-31 C000388 0-24 2018-01-01 2018-12-31 C000388 3-13 2018-01-01 2018-12-31 C000388 5-6 2018-01-01 2018-12-31 C000388 12-1 2018-01-01 2018-12-31 C000388 5-29 2018-01-01 2018-12-31 C000388 36-35 2018-01-01 2018-12-31 C000388 0-9 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 35-11 2018-01-01 2018-12-31 C000388 10-24 2018-01-01 2018-12-31 C000388 0-6 2018-12-31 C000388 17-33 2018-01-01 2018-12-31 C000388 16-40 2018-12-31 C000388 10-12 2018-01-01 2018-12-31 C000388 14-34 2018-01-01 2018-12-31 C000388 36-25 2018-01-01 2018-12-31 C000388 17-33 2018-01-01 2018-12-31 C000388 0-37 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-5 2018-12-31 C000388 2-14 2018-01-01 2018-12-31 C000388 ferc:OtherAncillaryServicesMember 2018-01-01 2018-12-31 C000388 0-20 2018-01-01 2018-12-31 C000388 26-13 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-42 2018-01-01 2018-12-31 C000388 8-17 2018-01-01 2018-12-31 C000388 12-14 2018-12-31 C000388 3-10 2018-01-01 2018-12-31 C000388 0-6 2018-01-01 2018-12-31 C000388 23-16 2018-01-01 2018-12-31 C000388 1-26 2018-01-01 2018-12-31 C000388 0-17 2018-01-01 2018-12-31 C000388 0-13 2018-12-31 C000388 1-12 2018-01-01 2018-12-31 C000388 0-5 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-1 2018-12-31 C000388 3-5 2017-12-31 C000388 0-36 2018-01-01 2018-12-31 C000388 2-29 2018-01-01 2018-12-31 C000388 1-3 2018-01-01 2018-12-31 C000388 0-24 2018-01-01 2018-12-31 C000388 5-36 2018-01-01 2018-12-31 C000388 19-2 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-26 2018-12-31 C000388 ferc:ElectricUtilityMember 1-21 2018-12-31 C000388 2 2018-01-01 2018-12-31 C000388 11-40 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-17 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-12 2018-12-31 C000388 0-13 2017-12-31 C000388 7-4 2018-01-01 2018-12-31 C000388 0-26 2018-12-31 C000388 27-6 2018-01-01 2018-12-31 C000388 30-1 2018-01-01 2018-12-31 C000388 16-29 2018-12-31 C000388 ferc:CommonPlantElectricMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C000388 3-36 2018-01-01 2018-12-31 C000388 0-28 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 2-6 2018-12-31 C000388 1-31 2018-01-01 2018-12-31 C000388 0-6 2018-01-01 2018-12-31 C000388 17-26 2018-01-01 2018-12-31 C000388 2-9 2018-01-01 2018-12-31 C000388 13-1 2018-01-01 2018-12-31 C000388 0-10 2018-12-31 C000388 0-27 2017-12-31 C000388 3-35 2018-01-01 2018-12-31 C000388 1-13 2018-01-01 2018-12-31 C000388 6-15 2018-01-01 2018-12-31 C000388 33-28 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-18 2018-12-31 C000388 1-22 2018-12-31 C000388 16-4 2018-01-01 2018-12-31 C000388 0-25 2018-01-01 2018-12-31 C000388 9-20 2018-12-31 C000388 0-31 2017-12-31 C000388 21-15 2018-01-01 2018-12-31 C000388 3-14 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 3-16 2018-01-01 2018-12-31 C000388 1-23 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 7-4 2018-01-01 2018-12-31 C000388 4-32 2018-01-01 2018-12-31 C000388 2-14 2018-12-31 C000388 ferc:ElectricUtilityMember 0-11 2018-12-31 C000388 0-8 2018-01-01 2018-12-31 C000388 12-10 2018-12-31 C000388 ferc:ElectricUtilityMember 6-20 2018-12-31 C000388 0-33 2018-01-01 2018-12-31 C000388 19-34 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 5-11 2018-12-31 C000388 0-22 2018-01-01 2018-12-31 C000388 28-25 2018-01-01 2018-12-31 C000388 7-40 2018-01-01 2018-12-31 C000388 4-4 2018-12-31 C000388 1-6 2018-01-01 2018-12-31 C000388 20-1 2018-01-01 2018-12-31 C000388 1-1 2018-01-01 2018-12-31 C000388 12-10 2018-01-01 2018-12-31 C000388 6-26 2018-01-01 2018-12-31 C000388 26-13 2018-01-01 2018-12-31 C000388 39-22 2018-01-01 2018-12-31 C000388 0-14 2018-01-01 2018-12-31 C000388 4-17 2018-01-01 2018-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 3-24 2018-12-31 C000388 23-20 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-8 2018-12-31 C000388 23-23 2018-01-01 2018-12-31 C000388 35-10 2018-01-01 2018-12-31 C000388 0-3 2018-01-01 2018-12-31 C000388 16-6 2018-12-31 C000388 1-23 2018-01-01 2018-12-31 C000388 5-25 2018-12-31 C000388 10-20 2018-01-01 2018-12-31 C000388 0-27 2018-01-01 2018-12-31 C000388 1-15 2018-01-01 2018-12-31 C000388 27-7 2018-01-01 2018-12-31 C000388 0-21 2018-12-31 C000388 2-29 2018-01-01 2018-12-31 C000388 17-14 2018-12-31 C000388 4-27 2018-01-01 2018-12-31 C000388 22-7 2018-01-01 2018-12-31 C000388 2-20 2018-01-01 2018-12-31 C000388 3-6 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-21 2018-01-01 2018-12-31 C000388 34-23 2018-01-01 2018-12-31 C000388 0-55 2018-01-01 2018-12-31 C000388 34-22 2018-01-01 2018-12-31 C000388 2-1 2018-12-31 C000388 ferc:ElectricUtilityMember 4-15 2018-01-01 2018-12-31 C000388 0-18 2018-01-01 2018-12-31 C000388 10-19 2018-01-01 2018-12-31 C000388 0-21 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 1-14 2018-12-31 C000388 3-7 2018-12-31 C000388 ferc:ElectricUtilityMember 3-9 2018-01-01 2018-12-31 C000388 0-1 2018-01-01 2018-12-31 C000388 2-11 2018-01-01 2018-12-31 C000388 0-11 2018-01-01 2018-12-31 C000388 38-18 2018-01-01 2018-12-31 C000388 3-15 2018-01-01 2018-12-31 C000388 0-4 2018-01-01 2018-12-31 C000388 15-13 2018-12-31 C000388 ferc:ElectricUtilityMember 3-41 2018-12-31 C000388 21-28 2018-01-01 2018-12-31 C000388 2-36 2018-12-31 C000388 14-40 2018-12-31 C000388 0-12 2018-01-01 2018-12-31 C000388 19-23 2018-01-01 2018-12-31 C000388 1-34 2018-01-01 2018-12-31 C000388 8-36 2018-12-31 C000388 39-13 2018-01-01 2018-12-31 C000388 14-29 2018-01-01 2018-12-31 C000388 4-35 2018-12-31 C000388 6-14 2018-01-01 2018-12-31 C000388 20-31 2018-01-01 2018-12-31 C000388 12-7 2018-01-01 2018-12-31 C000388 5-10 2018-01-01 2018-12-31 C000388 9-26 2018-12-31 C000388 1-42 2018-01-01 2018-12-31 C000388 0-13 2018-01-01 2018-06-30 C000388 17-12 2018-01-01 2018-12-31 C000388 11-27 2018-01-01 2018-12-31 C000388 28-5 2018-01-01 2018-12-31 C000388 20-12 2018-01-01 2018-12-31 C000388 28-11 2018-01-01 2018-12-31 C000388 0-8 2018-12-31 C000388 0-34 2018-01-01 2018-12-31 C000388 1-26 2018-12-31 C000388 4-2 2018-12-31 C000388 4-2 2018-01-01 2018-12-31 C000388 32-7 2018-01-01 2018-12-31 C000388 6-8 2018-01-01 2018-12-31 C000388 15-27 2018-01-01 2018-12-31 C000388 Colusa Gen Station-0 2018-01-01 2018-12-31 C000388 1-24 2018-01-01 2018-12-31 C000388 ferc:SulfurDioxideMember ferc:AfterThreeYearsMember 2018-01-01 2018-12-31 C000388 2-40 2018-01-01 2018-12-31 C000388 2-9 2017-12-31 C000388 0-13 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 6-21 2018-01-01 2018-12-31 C000388 10-6 2018-01-01 2018-12-31 C000388 3-21 2018-01-01 2018-12-31 C000388 ferc:GasUtilityMember 0-11 2018-12-31 C000388 ferc:ElectricUtilityMember 2-15 2018-12-31 C000388 4-23 2018-01-01 2018-12-31 C000388 1-16 2018-01-01 2018-12-31 C000388 2-5 2017-12-31 C000388 3-28 2018-01-01 2018-12-31 C000388 3-3 2018-01-01 2018-12-31 C000388 0-21 2018-12-31 C000388 0-18 2018-01-01 2018-12-31 C000388 0-26 2018-01-01 2018-09-30 C000388 30-20 2018-01-01 2018-12-31 C000388 0-26 2018-01-01 2018-12-31 C000388 15-9 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 4-13 2018-01-01 2018-12-31 C000388 0-9 2018-12-31 C000388 1-19 2018-01-01 2018-12-31 C000388 0-33 2018-01-01 2018-12-31 C000388 10-31 2018-12-31 C000388 0-5 2018-01-01 2018-12-31 C000388 ferc:ElectricUtilityMember 0-6 2018-01-01 2018-12-31 C000388 18-4 2018-01-01 2018-12-31 C000388 0-14 2018-12-31 C000388 0-18 2018-12-31 C000388 14-8 2018-01-01 2018-12-31 C000388 0-32 2018-01-01 2018-12-31 C000388 1-33 2018-01-01 2018-12-31 C000388 0-4 2018-01-01 2018-12-31 C000388 15-36 2018-12-31 C000388 2-30 2018-01-01 2018-12-31 C000388 0-4 2018-12-31 C000388 0-11 2018-01-01 2018-12-31 iso4217:USD utr:MMBTU pure utr:mi pure utr:mi utr:kV utr:MWh iso4217:USD utr:kWh iso4217:USD utr:Btu utr:kWh iso4217:USD shares utr:kWh ferc:MVa iso4217:USD utr:MW shares utr:MW
THIS FILING IS
Item 1:
An Initial (Original) Submission
OR
Resubmission No.

FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. 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 confidential nature
Exact Legal Name of Respondent (Company)

PACIFIC GAS AND ELECTRIC COMPANY
Year/Period of Report

End of:
2018
/
Q4


INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION

  1. Purpose

    FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.
  2. Who Must Submit

    Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 141.400).

    Note: Major means having, in each of the three previous calendar years, sales or transmission service that exceeds one of the following:
    1. one million megawatt hours of total annual sales,
    2. 100 megawatt hours of annual sales for resale,
    3. 500 megawatt hours of annual power exchanges delivered, or
    4. 500 megawatt hours of annual wheeling for others (deliveries plus losses).
  3. What and Where to Submit

    1. Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site: http://www.ferc.gov/docs-filing/forms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet.
    2. The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings.
    3. Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at:
      Secretary
      Federal Energy Regulatory Commission 888 First Street, NE
      Washington, DC 20426
    4. For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

      The CPA Certification Statement should:
      1. Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System 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. §§ 41.10-41.12 for specific qualifications.)

        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
    5. The following format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported.

      “In connection with our regular examination of the financial statements of for the year ended on which we have reported separately under date of , we have also reviewed schedules of FERC Form No. 1 for the year filed with the Federal Energy Regulatory Commission, for conformity in all material respects with the requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases. Our review for this purpose included such tests of the accounting records and such other auditing procedures as we considered necessary in the circumstances.

      Based on our review, in our opinion the accompanying schedules identified in the preceding paragraph (except as noted below) conform in all material respects with the accounting requirements of the Federal Energy Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist.
    6. 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’s website at http://www.ferc.gov/help/how-to.asp.
    7. Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from http://www.ferc.gov/docs-filing/forms/form-1/form-1.pdf and http://www.ferc.gov/docs-filing/forms.asp#3Q-gas .
  4. When to Submit

    FERC Forms 1 and 3-Q must be filed by the following schedule:

    1. FERC Form 1 for each year ending December 31 must be filed by April 18th of the following year (18 CFR § 141.1), and
    2. FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400).
  5. Where to Send Comments on Public Reporting Burden.

    The public reporting burden for the FERC Form 1 collection of information is estimated to average 1,168 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 FERC Form 3-Q collection of information is estimated to average 168 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 this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA.
  2. Enter in whole numbers (dollars or MWH) 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 (see VII. below).
  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 software only. Please explain the reason for the resubmission in a footnote to the data field.
  8. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized.
  9. 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.
Definitions for statistical classifications used for completing schedules for transmission system reporting are as follows:

FNS - Firm Network Transmission Service for Self. "Firm" means service that can not be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff. "Self" means the respondent.

FNO - Firm Network Service for Others. "Firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Network Service" is Network Transmission Service as described in Order No. 888 and the Open Access Transmission Tariff.

LFP - for Long-Term Firm Point-to-Point Transmission Reservations. "Long-Term" means one year or longer and” firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally cancel the contract.

OLF - Other Long-Term Firm Transmission Service. Report service provided under contracts which do not conform to the terms of the Open Access Transmission Tariff. "Long-Term" means one year or longer and “firm” means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions. For all transactions identified as OLF, provide in a footnote the termination date of the contract defined as the earliest date either buyer or seller can unilaterally get out of the contract.

SFP - Short-Term Firm Point-to-Point Transmission Reservations. Use this classification for all firm point-to-point transmission reservations, where the duration of each period of reservation is less than one-year.

NF - Non-Firm Transmission Service, where firm means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions.

OS - Other Transmission Service. Use this classification only for those services which can not be placed in the above-mentioned classifications, such as all other service regardless of the length of the contract and service FERC Form. Describe the type of service in a footnote for each entry.

AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment.

DEFINITIONS
  1. Commission Authorization (Comm. Auth.) -- 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.
  2. Respondent -- The person, corporation, licensee, agency, authority, or other Legal entity or instrumentality in whose behalf the report is made.

EXCERPTS FROM THE LAW

Federal Power Act, 16 U.S.C. § 791a-825r

Sec. 3. The words defined in this section shall have the following meanings for purposes of this Act, to with:

  1. ’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined;
  2. 'Person' means an individual or a corporation;
  3. 'Licensee, means any person, State, or municipality Licensed under the provisions of section 4 of this Act, and any assignee or successor in interest thereof;
  1. 'municipality means a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the Laws thereof to carry and the business of developing, transmitting, unitizing, or distributing power; ......
  1. "project' means. a complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights-of-way, ditches, dams, reservoirs, Lands, or interest in Lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit;

"Sec. 4. The Commission is hereby authorized and empowered
  1. 'To make investigations and to collect and record data concerning the utilization of the water 'resources of any region to be developed, the water-power industry and its relation to other industries and to interstate or foreign commerce, and concerning the location, capacity, development -costs, and relation to markets of power sites; ... to the extent the Commission may deem necessary or useful for the purposes of this Act."

"Sec. 304.
  1. Every Licensee and every public utility shall file with the Commission such annual and other periodic or special* reports as the Commission may be rules and regulations or other prescribe as necessary or appropriate to assist the Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports salt be made, and require from such persons specific answers to all questions upon which the Commission may need information. The Commission may require that such reports shall include, among other things, full information as to assets and Liabilities, capitalization, net investment, and reduction thereof, gross receipts, interest due and paid, depreciation, and other reserves, cost of project and other facilities, cost of maintenance and operation of the project and other facilities, cost of renewals and replacement of the project works and other facilities, depreciation, generation, transmission, distribution, delivery, use, and sale of electric energy. The Commission may require any such person to make adequate provision for currently determining such costs and other facts. Such reports shall be made under oath unless the Commission otherwise specifies*.10
"Sec. 309.
  1. The Commission shall have power to perform any and all acts, and to prescribe, issue, make, 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 FERC Form or FERC Forms of all statements, declarations, applications, and reports to be filed with the Commission, the information which they shall contain, and the time within which they shall be field..."

GENERAL PENALTIES

The Commission may assess up to $1 million per day per violation of its rules and regulations. See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).


FERC FORM NO.
1

REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
IDENTIFICATION
01 Exact Legal Name of Respondent

PACIFIC GAS AND ELECTRIC COMPANY
02 Year/ Period of Report


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

PACIFIC GAS AND ELECTRIC COMPANY
/
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)

77 BEALE STREET, P.O BOX 770000, SAN FRANCISCO, CA 94177
05 Name of Contact Person

RACHEL PETERSEN
06 Title of Contact Person

DIRECTOR, CORP ACCOUNTING
07 Address of Contact Person (Street, City, State, Zip Code)

77 BEALE STREET, Mail Code B7A, P.O BOX 770000, SAN FRANCISCO, CA 94177
08 Telephone of Contact Person, Including Area Code

(415) 973-1700
09 This Report is An Original / A Resubmission

(1)
An Original

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

04/16/2019
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.

01 Name

DAVID THOMASON
02 Title

VP, CONTROLLER, UTILITY CFO
03 Signature

04 Date Signed (Mo, Da, Yr)

04/16/2019
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:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
LIST OF SCHEDULES (Electric Utility)

Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

Line No.
Title of Schedule
(a)
Reference Page No.
(b)
Remarks
(c)
ScheduleIdentificationAbstract
Identification
1
ScheduleListOfSchedulesAbstract
List of Schedules
2
1
ScheduleGeneralInformationAbstract
General Information
101
2
ScheduleControlOverRespondentAbstract
Control Over Respondent
102
3
ScheduleCorporationsControlledByRespondentAbstract
Corporations Controlled by Respondent
103
4
ScheduleOfficersAbstract
Officers
104
5
ScheduleDirectorsAbstract
Directors
105
6
ScheduleInformationOnFormulaRatesAbstract
Information on Formula Rates
106
NOT APPLICABLE
7
ScheduleImportantChangesDuringTheQuarterYearAbstract
Important Changes During the Year
108
8
ScheduleComparativeBalanceSheetAbstract
Comparative Balance Sheet
110
9
ScheduleStatementOfIncomeAbstract
Statement of Income for the Year
114
10
ScheduleRetainedEarningsAbstract
Statement of Retained Earnings for the Year
118
11
ScheduleStatementOfCashFlowsAbstract
Statement of Cash Flows
120
12
ScheduleNotesToFinancialStatementsAbstract
Notes to Financial Statements
122
13
ScheduleStatementOfAccumulatedOtherComprehensiveIncomeAndHedgingActivitiesAbstract
Statement of Accum Other Comp Income, Comp Income, and Hedging Activities
122a
14
ScheduleSummaryOfUtilityPlantAndAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep
200
15
ScheduleNuclearFuelMaterialsAbstract
Nuclear Fuel Materials
202
16
ScheduleElectricPlantInServiceAbstract
Electric Plant in Service
204
17
ScheduleElectricPropertyLeasedToOthersAbstract
Electric Plant Leased to Others
213
NONE
18
ScheduleElectricPlantHeldForFutureUseAbstract
Electric Plant Held for Future Use
214
NONE
19
ScheduleConstructionWorkInProgressElectricAbstract
Construction Work in Progress-Electric
216
20
ScheduleAccumulatedProvisionForDepreciationOfElectricUtilityPlantAbstract
Accumulated Provision for Depreciation of Electric Utility Plant
219
21
ScheduleInvestmentsInSubsidiaryCompaniesAbstract
Investment of Subsidiary Companies
224
22
ScheduleMaterialsAndSuppliesAbstract
Materials and Supplies
227
23
ScheduleAllowanceInventoryAbstract
Allowances
228
24
ScheduleExtraordinaryPropertyLossesAbstract
Extraordinary Property Losses
230a
NONE
25
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant and Regulatory Study Costs
230b
26
ScheduleTransmissionServiceAndGenerationInterconnectionStudyCostsAbstract
Transmission Service and Generation Interconnection Study Costs
231
27
ScheduleOtherRegulatoryAssetsAbstract
Other Regulatory Assets
232
28
ScheduleMiscellaneousDeferredDebitsAbstract
Miscellaneous Deferred Debits
233
29
ScheduleAccumulatedDeferredIncomeTaxesAbstract
Accumulated Deferred Income Taxes
234
30
ScheduleCapitalStockAbstract
Capital Stock
250
31
ScheduleOtherPaidInCapitalAbstract
Other Paid-in Capital
253
32
ScheduleCapitalStockExpenseAbstract
Capital Stock Expense
254b
33
ScheduleLongTermDebtAbstract
Long-Term Debt
256
34
ScheduleReconciliationOfReportedNetIncomeWithTaxableIncomeForFederalIncomeTaxesAbstract
Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax
261
35
ScheduleTaxesAccruedPrepaidAndChargedDuringYearDistributionOfTaxesChargedAbstract
Taxes Accrued, Prepaid and Charged During the Year
262
36
ScheduleAccumulatedDeferredInvestmentTaxCreditsAbstract
Accumulated Deferred Investment Tax Credits
266
37
ScheduleOtherDeferredCreditsAbstract
Other Deferred Credits
269
38
ScheduleAccumulatedDeferredIncomeTaxesAcceleratedAmortizationPropertyAbstract
Accumulated Deferred Income Taxes-Accelerated Amortization Property
272
39
ScheduleAccumulatedDeferredIncomeTaxesOtherPropertyAbstract
Accumulated Deferred Income Taxes-Other Property
274
40
ScheduleAccumulatedDeferredIncomeTaxesOtherAbstract
Accumulated Deferred Income Taxes-Other
276
41
ScheduleOtherRegulatoryLiabilitiesAbstract
Other Regulatory Liabilities
278
42
ScheduleElectricOperatingRevenuesAbstract
Electric Operating Revenues
300
43
ScheduleRegionalTransmissionServiceRevenuesAbstract
Regional Transmission Service Revenues (Account 457.1)
302
NOT APPLICABLE
44
ScheduleSalesOfElectricityByRateSchedulesAbstract
Sales of Electricity by Rate Schedules
304
45
ScheduleSalesForResaleAbstract
Sales for Resale
310
46
ScheduleElectricOperationsAndMaintenanceExpensesAbstract
Electric Operation and Maintenance Expenses
320
47
SchedulePurchasedPowerAbstract
Purchased Power
326
48
ScheduleTransmissionOfElectricityForOthersAbstract
Transmission of Electricity for Others
328
49
ScheduleTransmissionOfElectricityByIsoOrRtoAbstract
Transmission of Electricity by ISO/RTOs
331
NOT APPLICABLE
50
ScheduleTransmissionOfElectricityByOthersAbstract
Transmission of Electricity by Others
332
51
ScheduleMiscellaneousGeneralExpensesAbstract
Miscellaneous General Expenses-Electric
335
52
ScheduleDepreciationDepletionAndAmortizationAbstract
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
336
53
ScheduleRegulatoryCommissionExpensesAbstract
Regulatory Commission Expenses
350
54
ScheduleResearchDevelopmentOrDemonstrationExpendituresAbstract
Research, Development and Demonstration Activities
352
55
ScheduleDistributionOfSalariesAndWagesAbstract
Distribution of Salaries and Wages
354
56
ScheduleCommonUtilityPlantAndExpensesAbstract
Common Utility Plant and Expenses
356
57
ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract
Amounts included in ISO/RTO Settlement Statements
397
58
SchedulePurchasesSalesOfAncillaryServicesAbstract
Purchase and Sale of Ancillary Services
398
59
ScheduleMonthlyTransmissionSystemPeakLoadAbstract
Monthly Transmission System Peak Load
400
60
ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract
Monthly ISO/RTO Transmission System Peak Load
400a
NOT APPLICABLE
61
ScheduleElectricEnergyAccountAbstract
Electric Energy Account
401a
62
ScheduleMonthlyPeakAndOutputAbstract
Monthly Peaks and Output
401b
63
ScheduleSteamElectricGeneratingPlantStatisticsAbstract
Steam Electric Generating Plant Statistics
402
64
ScheduleHydroelectricGeneratingPlantStatisticsAbstract
Hydroelectric Generating Plant Statistics
406
65
SchedulePumpedStorageGeneratingPlantStatisticsAbstract
Pumped Storage Generating Plant Statistics
408
66
ScheduleGeneratingPlantStatisticsAbstract
Generating Plant Statistics Pages
410
0
ScheduleEnergyStorageOperationsLargePlantsAbstract
Energy Storage Operations (Large Plants)
414
67
ScheduleTransmissionLineStatisticsAbstract
Transmission Line Statistics Pages
422
68
ScheduleTransmissionLinesAddedAbstract
Transmission Lines Added During Year
424
69
ScheduleSubstationsAbstract
Substations
426
70
ScheduleTransactionsWithAssociatedAffiliatedCompaniesAbstract
Transactions with Associated (Affiliated) Companies
429
71
FootnoteDataAbstract
Footnote Data
450
StockholdersReportsAbstract
Stockholders' Reports (check appropriate box)
Stockholders' Reports Check appropriate box:

Two copies will be submitted

No annual report to stockholders is prepared


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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.

David S. Thomason, Vice President, Controller, and CFO 77 Beale Street, B11H San Francisco, CA 94105

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.

California - October 10, 1905

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.

Electricity and natural gas distribution, electric generation, procurement, and transmission, and natural gas procurement, transportation, and storage. State of California only.
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:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
CONTROL OVER RESPONDENT
1. If any corporation, business trust, or similar organization or a combination of such organizations jointly held control over the respondent at the end of the year, state name of controlling corporation or organization, manner in which control was held, and extent of control. If control was in a holding company organization, show the chain of ownership or control to the main parent company or organization. If control was held by a trustee(s), state name of trustee(s), name of beneficiary or beneficiaries for whom trust was maintained, and purpose of the trust.
Effective January 1, 1997, PG&E Corporation became the holding company of Pacific Gas and Electric Company.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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.
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 which 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)
CompanyControlledByRespondentKindOfBusinessDescription
Kind of Business
(b)
VotingStockOwnedByRespondentPercentage
Percent Voting Stock Owned
(c)
FootnoteReferences
Footnote Ref.
(d)
1
Eureka Energy Company
Formerly managed
100
2
the Utility's Utah coal
3
venture. Currently holds
4
part of the Marre Ranch
5
property in San Luis
6
Obispo County.
7
Midway Power, LLC
Formed to be the ownership
100
8
entity for real estate and
9
licenses for a suspended
10
development project.
11
Natural Gas Corporation of California (NGC)
Entity used to amortize
100
12
remaining Gas
13
Exploration and
14
Development Account
15
assets.
16
FuelCo LLC
Formed to share costs and
50
17
reduce fuel acquisition
18
costs.
19
Pacific Energy Fuels Company
Formed to own and
100
20
finance the nuclear fuel
21
inventory previously owned
22
by Pacific Energy Trust
23
Standard Pacific Gas Line Incorporated
Engaged in the transportation
85.71
24
of natural gas in California.
25
The Utility owns an 85.71%
26
interest and Chevron Pipe
27
Line Company owns the
28
remaining 14.29% interest.
29
Morro Bay Mutual Water Company
Formed to jointly hold
50
30
property rights in connection
31
with the divestiture of the
32
Morro Bay Power Plant.
33
Moss Landing Mutual Water Company
Formed to jointly hold
33
34
propert rights in connection
35
with the divestiture of the
36
Moss Landing Power Plant.
37
Alaska Gas Exploration Associates
Formed to explore,
100
38
develop, produce, acquire,
39
and market oil and gas
40
reserves in Alaska.
41
STARS Alliance, LLC
Formed to increase efficiency
25
42
and reduce costs related to
43
the operation of the members
44
nuclear generation
45
facilities.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: FootnoteReferences

Members include: Union Electric Company d/b/a AmerenMO.

12/8/17 - Certificate of Withdrawal filed with the state of Texas

(b) Concept: FootnoteReferences

Members include: Dynergy Moss Landing. Pacific Gas and Electric Company is one of 2 members of the non-profit mutual benefit corporation.

(c) Concept: FootnoteReferences

Members include: Dynergy Moss Landing and Moon Glow Dairy. Pacific Gas and Electric Company is one of 3 members of the non-profit mutual benefit corporation.

(d) Concept: FootnoteReferences

Currently inactive

(e) Concept: FootnoteReferences

Members include: Arizona Public Service Company, Union Electric Company, d/b/a AmerenMO, and Wolf Creek Nuclear Operating Corporation. Pacific Gas and Electric Company has a 1/4 equity interest.

 

Waiting for confirmation of withdrawal from Texas.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
OFFICERS
  1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions.
  2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.
Line No.
OfficerTitle
Title
(a)
OfficerName
Name of Officer
(b)
OfficerSalary
Salary for Year
(c)
DateOfficerIncumbencyStarted
Date Started in Period
(d)
DateOfficerIncumbencyEnded
Date Ended in Period
(e)
1
Senior VP, Human Resources and Chief Diversity Officer
Dinyar B. Mistry
504,167
2
Senior VP, Gas Operations
Jesus Soto, Jr.
474,333
3
Senior VP and Chief Ethics and Compliance Officer and
Julie M. Kane
470,197
4
Deputy General Council
5
Senior VP and Chief Customer Officer
Loraine M. Giammona
461,667
6
Senior VP, Energy Supply and Policy
(a)
Steven Malnight
460,633
7
Senior VP, Electric Operation
Patrick M. Hogan
422,500
8
Senior VP, Energy Policy and Procurement
Fong Wan
410,833
9
Senior VP and Chief Information Officer
(b)
Kathleen B. Kay
387,333
10
Senior VP and Deputy General Counsel of the Utility
(c)
Janet C. Loduca
370,850
11
Vice President, Chief Financial Officer and Controller
David S. Thomason
320,833
12
Special Advisor
(d)
Nickolas Stavropoulos
618,667
13
Senior VP and Cheif Information Officer
(e)
Karen A. Austin
477,833


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OfficerName

Mr. Malnight, formerly Senior VP, Strategy and Policy, became Senior VP, Energy Supply and Policy on September 1, 2018.

(b) Concept: OfficerName

Ms. Kay, formerly VP, Business Technology, became Senior VP and Chief Information Officer on September 1, 2018.

(c) Concept: OfficerName

Ms. Loduca, formerly VP and Deputy General Counsel, became Senior VP and Deputy General Counsel on December 1, 2018

(d) Concept: OfficerName

Mr. Stavropoulos, formerly President and Chief Operating Officer, became Special Advisor on September 1, 2018. Mr. Stavropoulos' employement ended October 1, 2018.

 

(e) Concept: OfficerName

Ms. Austin's employment ended November 1, 2018.

 


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
DIRECTORS
  1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent.
  2. Designate members of the Executive Committee in column (c) and the Chairman of the Executive Committee in column (d).
Line No.
NameAndTitleOfDirector
Name (and Title) of Director
(a)
PrincipalBusinessAddress
Principal Business Address
(b)
MemberOfTheExecutiveCommittee
Member of the Executive Committee
(c)
ChairmanOfTheExecutiveCommittee
Chairman of the Executive Committee
(d)
1
Lewis Chew ***
c/o PG&E Corporation
2
77 Beale Street, 32nd Floor
3
San Francisco, CA 94105
4
Fred J. Fowler
c/o PG&E Corporation
5
77 Beale Street, 32nd Floor
6
San Francisco, CA 94105
7
Richard C. Kelly **
c/o PG&E Corporation
8
77 Beale Street, 32nd Floor
9
San Francisco, CA 94105
10
Roger H. Kimmel
c/o PG&E Corporation
11
77 Beale Street, 32nd Floor
12
San Francisco, CA 94105
13
Richard A. Meserve ***
c/o PG&E Corporation
14
77 Beale Street, 32nd Floor
15
San Francisco, CA 94105
16
Forrest E. Miller ***
c/o PG&E Corporation
17
77 Beale Street, 32nd Floor
18
San Francisco, CA 94105
19
Benito Minicucci
c/o PG&E Corporation
20
77 Beale Street, 32nd Floor
21
San Francisco, CA 94105
22
Eric D. Mullins
c/o PG&E Corporation
23
77 Beale Street, 32nd Floor
24
San Francisco, CA 94105
25
Rosendo G. Parra
c/o PG&E Corporation
26
77 Beale Street, 32nd Floor
27
San Francisco, CA 94105
28
Barbara L. Rambo ***
c/o PG&E Corporation
29
77 Beale Street, 32nd Floor
30
San Francisco, CA 94105
31
Anne Shen Smith ***
c/o PG&E Corporation
32
77 Beale Street, 32nd Floor
33
San Francisco, CA 94105
34
Geisha J. Williams
c/o PG&E Corporation
35
77 Beale Street, 32nd Floor
36
San Francisco, CA 94105


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES
Does the respondent have formula rates?
Yes

No
  1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No) accepting the rate(s) or changes in the accepted rate.
Line No.
RateScheduleTariffNumber
FERC Rate Schedule or Tariff Number
(a)
ProceedingDocketNumber
FERC Proceeding
(b)
1
NOT APPLICABLE


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES - FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent) filings containing the inputs to the formula rate(s)?
Yes

No
  1. If yes, provide a listing of such filings as contained on the Commission's eLibrary website.
Line No.
AccessionNumber
Accession No.
(a)
DocumentDate
Document Date / Filed Date
(b)
DocketNumber
Docket No.
(c)
DescriptionOfFiling
Description
(d)
RateScheduleTariffNumber
Formula Rate FERC Rate Schedule Number or Tariff Number
(e)
1
NOT APPLICABLE


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
INFORMATION ON FORMULA RATES - Formula Rate Variances
  1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from amounts reported in the Form 1.
  2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the Form 1.
  3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
  4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line No.
PageNumberOfFormulaRateVariances
Page No(s).
(a)
ScheduleOfFormulaRateVariances
Schedule
(b)
ColumnOfFormulaRateVariances
Column
(c)
LineNumberOfFormulaRateVariances
Line No.
(d)
1
NOT APPLICABLE


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR

Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.

  1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the franchise rights were acquired. If 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: Give a brief description of the property, and of the transactions relating thereto, and reference to Commission authorization, if any was required. Give date journal entries called for by the 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 condition. 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 give reference to 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 as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee.
  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 reported on Page 104 or 105 of the Annual Report Form No. 1, 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. (Reserved.)
  12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
  13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period.
  14. 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.

PACIFIC GAS AND ELECTRIC COMPANY

IMPORTANT CHANGES DURING THE YEAR

 

For the Quarter Ended December 31, 2018

 

 

 

1. Changes in and important additions to franchise rights:

There are no changes in or additions to PG&E’s franchise rights.

 

  1. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies:

 

None.

  1. Purchase or sale of an operating unit or system:

 

Sale:

 

None.

 

Purchase:

 

None.

 

  1. Important leaseholds that have been acquired or given, assigned or surrendered:

 

None.

 

  1. Important extension or reduction of transmission or distribution system:

 

Electric:

 

On February 8, 2018, the Crescent Switching Station was released to operations. This project, located in Fresno County, constructed a new 6 circuit breaker-and-a-half (BAAH) 70 kV Switching Station. This project was built to facilitate the interconnection of a 20 MW solar generation by San Joaquin 1A Solar to Pacific Gas and Electric Company’s Helm – Stroud & Stroud Sw Sta – Schindler 70 kV Lines.

 

On February 15, 2018, the Midway Fault Duty Mitigation Project was released to operations. This project, located in Kern County, installed 9 ohm series reactors at the 230 kV side of Midway 500/230 kV Transformer Banks 11, 12 and 13. This project was built to mitigate excessive fault duty, which was projected to increase beyond the specified safe limits as a result of various generation interconnection projects at Midway Substation.

 

On April 17, 2018, the Warnerville-Wilson 230 kV Series Reactor Project was released to operations. This project, located in Fresno County, installed 230 kV multi-step series reactors totaling 50.5 Ohms at the Wilson Substation on the Warnerville-Wilson 230 kV line. This project was built to provide additional transmission capacity and reliability to serve electric customers, and to address potential overload conditions in Central California/Fresno area.

 

On July 15, 2018, Cheney Substation was removed from operations. This project, located in Fresno County, decommissioned the 115 kV Substation and permanently tied together the Cheney #1 & Cheney #2 115 kV lines to bypass the station. The addition of a new distribution transformer with associated bus and breakers at Panoche Substation and electric service transfer of all Cheney distribution feeders to Panoche Substation resulted in the full decommissioning of Cheney Substation to improve service reliability and operational flexibility in northwest Fresno County.

 

On August 7, 2018, the Stroud Switching Station was removed from operations. This project, located in Fresno County, decommissioned the 70 kV Switching Station and constructed a new 6 circuit breaker-and-a-half (BAAH) 70 kV Crescent Switching Station. This project was built to facilitate the interconnection of a 20 MW solar generation by San Joaquin 1A Solar to Pacific Gas and Electric Company’s Helm – Crescent Sw Sta & Crescent Sw Sta – Schindler 70 kV Lines.

 

Gas:

 

None.

 

 

  1. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term debt and commercial paper having maturity of one year or less. Give reference to FERC or State Commission authorization, as appropriate, and the amount of obligation or guarantee:

 

 

a) Financings:

 

There were no Long-Term borrowings during the quarter ending December 31, 2018.

 

Long-term borrowings are authorized by the California Public Utilities Commission (“CPUC”) Decision No. 15-01-030.

 

There were no Short-Term borrowings during the quarter ending December 31,2018.

 

Short-term borrowings are authorized by CPUC Decision No. 09-05-002.

 

 

b) Bank Credit Facilities:

 

At December 31, 2018, the Utility had $80 million of letters of credit outstanding, no commercial paper outstanding, and

$2.9 billion of borrowings under its revolving credit facility. Short-term borrowings are authorized by CPUC Decision No. 09-05-002.

 

c) Surety Bonds and Financial Guarantees Backed by Insurance:

 

From October 01, 2018 to December 31, 2018, $ 25,000.00 in surety bond obligations were issued in conformance with the CPUC Decision No. 12-04-015. As of December 31, 2018, there was a total of $119,696,568.25 in long-term surety bond obligations outstanding.

 

d) Capital Support:

 

CPUC Decision No. 91-12-057 (as modified by Decision No. 99-04-068) authorized the Utility to provide capital support to regulated and unregulated subsidiaries. At December 31, 2018, the Utility has no outstanding future capital commitments to unregulated subsidiaries and affiliates.

 

 

e) Preferred stock repayments:

None.

  1. Changes in articles of incorporation or amendments to charter. Explain the nature and purpose of such changes or amendments:

 

None.

 

  1. State the estimated annual effect and nature of any important wage scale changes during the period:

 

None.

  1. State briefly the status of any materially important legal proceedings pending at the end of the period and the results of any such proceedings culminated during the period:

 

Refer to Part I, Item 3 in PG&E Corporation and the Utility’s joint Annual Report on Form 10-K for the year ended December 31, 2018, which describes certain legal proceedings pursuant to Item 103 of Regulation S-K of the Securities Exchange Act of 1934, as amended.  Four copies of the Form 10—K report are filed in accordance with Instruction III(c) of Instructions For Filing the FERC Form No. 1. 

 

  1. Describe briefly any materially important transactions of the not disclosed elsewhere in this report in which an officer, director, security holder reported on Page 106, 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:

 

“Five Percent Owners”

 

 

During the fourth quarter of 2018, three beneficial owners of at least 5 percent of PG&E Corporation common stock as of December 31, 2017 provided asset management services to PG&E Corporation, Pacific Gas and Electric Company (“Utility”), and related entities: BlackRock,?Inc. ("BlackRock"), T. Rowe Price Associates Inc. (“Price Associates”), and the Vanguard Group (“Vanguard”). These entities were identified based solely on a review of Schedule 13Gs (or any amendments) filed with the Securities and Exchange Commission by February 15, 2018.

 

Specifically, these entities provided asset management services to various trusts associated with PG&E Corporation’s and the Utility’s employee benefit plans, to the Utility's nuclear decommissioning trusts, to the trusts securing benefits in the event of a change in control, and the PG&E Corporation Foundation. In each of these cases (with the exception of Vanguard), the services were initiated before the entity became a 5? percent shareholder. In each of these cases, the services are subject to terms comparable to those that could be obtained in arm's-length dealings with an unrelated third party. PG&E Corporation and the Utility expect that these entities will continue to provide similar services and products in the future, in the normal course of business operations.

 

 

During 2018, each of these parties is expected to provide services in excess of the $120,000 disclosure threshold set forth in SEC Reg. S-K, Item 404(a).

 

“Immediate Family Members”

 

 

Kathy Thomason is employed by the Utility as a Business Finance Analyst, Expert. She is the wife of David Thomason, who is Vice President, Chief Financial Officer, and Controller of the Utility and an executive officer of the Utility. Ms. Thomason is, therefore, an “immediate family member” for purposes of SEC related person transaction disclosure rules. While Ms. Thomason is employed with the Utility, she will receive salary, short-term incentive awards, and other cash compensation and benefits consistent with the Utility’s standard compensation practices and policies.

 

We expect that the value of payments to Ms. Thomason for the period January 2018 through March 2019 (assuming she remains employed with the Utility during that period) will be close to the $120,000 disclosure threshold set forth in SEC Reg S-K. Item 404(a).

 

  1. (Reserved)

 

  1. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are applicable in every respect and furnish the data required by instructions to 1 to 11 above, such notes may be included on this page.

 

Not applicable.

 

  1. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred during the reporting period:

 

Directors

 

The following individual was elected as a Director of the Utility:

 

• Benito Minicucci, Director

 

The following individual is no longer a Director of the Utility:

 

• Nickolas Stavropoulos, Director

 

Officers

 

The following individuals became an officer of the Utility:

 

• Michael A. Lewis, Vice President Electric Distribution Operations

 

The following individual’s titles changed:

 

• Nickolas Stavropoulos, Special Advisor to the Utility (formerly President and Chief Operating Officer)

 

• Janet C. Loduca, Senior Vice President and Deputy General Counsel(formerly Vice President and Deputy General Counsel)

 

• Kathleen B. Kay, Senior Vice President and Chief Information Officer (formerly Vice President,Business Technology)

 

• Steven E. Malnight, Senior Vice President, Energy Supply and Policy (formerly Senior Vice President, Strategy and Policy)

 

• Barry D. Anderson, Vice President, Wildfire Resiliency and Emergency Management (formerly Vice President, Electric Distribution)

 

• Jon A. Franke, Vice President, Safety and Health and Chief Safety Officer (formerly Vice President, Power Generation)

 

• Gun S. Shim, Vice President

and Chief Procurement Officer (formerly Vice President, Supply Chain Management)

 

• Sumeet Singh, Vice President, Community Wildfire Safety Program

(formerly Vice President, Gas Asset and Risk Management)

 

The following individual is no longer an officer of the Utility:

• Nickolas Stavropoulos, Special Advisor to the Utility

 

• Barry D. Anderson, Vice President, Wildfire Resiliency and Emergency Management

 

• Karen A. Austin, Senior Vice President and Chief Information Officer

 

• Timothy Fitzpatrick, Vice President, Corporate Relations and Chief Communications Officer

 

• John C. Higgins, Vice President, Safety & Health, and

Chief Safety Office

 

Major Security Holders

 

Changes to the major holders of the Utility’s First Preferred Stock are as follows:

 

Cede & Co., C/O DTCC-Transfer Operation Dept., 570 Washington Blvd Floor 1, Jersey City, NJ 08857, increased its share ownership from 9,556,157 shares as of December 31, 2017 to 9,632,045 shares as of December 31, 2018. (Approximately 93 percent of the total preferred shares outstanding).

 

Dividend Payments

 

Refer to Note X, Equity of the Notes to Financial Statements on page XXX of the FERC Form 4-Q.

 

14. 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:

 

Not applicable.

 


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line No.
Title of Account
(a)
Ref. Page No.
(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
86,967,343,203
81,000,792,691
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200
2,562,027,669
2,470,588,868
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Enter Total of lines 2 and 3)
89,529,370,872
83,471,381,559
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
200
37,353,599,037
35,680,789,356
6
UtilityPlantNet
Net Utility Plant (Enter Total of line 4 less 5)
52,175,771,835
47,790,592,203
7
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
202
233,949,233
261,763,030
8
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9
NuclearFuelAssembliesInReactorMajorOnly
Nuclear Fuel Assemblies in Reactor (120.3)
427,381,622
416,084,176
10
SpentNuclearFuelMajorOnly
Spent Nuclear Fuel (120.4)
2,359,998,526
2,265,141,307
11
NuclearFuelUnderCapitalLeases
Nuclear Fuel Under Capital Leases (120.6)
12
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
202
2,630,936,779
2,505,050,242
13
NuclearFuelNet
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
390,392,602
437,938,271
14
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Enter Total of lines 6 and 13)
52,566,164,437
48,228,530,474
15
OtherElectricPlantAdjustments
Utility Plant Adjustments (116)
16
GasStoredUndergroundNoncurrent
Gas Stored Underground - Noncurrent (117)
55,907,325
55,907,325
17
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
18
NonutilityProperty
Nonutility Property (121)
29,171,933
30,929,381
19
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Prov. for Depr. and Amort. (122)
20
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
21
InvestmentInSubsidiaryCompanies
Investment in Subsidiary Companies (123.1)
224
50,082,345
48,859,887
23
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
228
(a)
355,147,460
(f)
195,017,512
24
OtherInvestments
Other Investments (124)
10,942
10,942
25
SinkingFunds
Sinking Funds (125)
26
DepreciationFund
Depreciation Fund (126)
27
AmortizationFundFederal
Amortization Fund - Federal (127)
28
OtherSpecialFunds
Other Special Funds (128)
2,729,720,970
2,863,247,030
29
SpecialFunds
Special Funds (Non Major Only) (129)
545,313,624
553,022,543
30
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
(b)
165,299,922
(g)
102,130,395
31
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
32
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
3,874,747,196
3,793,217,690
33
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
34
CashAndWorkingFunds
Cash and Working Funds (Non-major Only) (130)
35
Cash
Cash (131)
71,327,413
57,718,289
36
SpecialDeposits
Special Deposits (132-134)
6,886,597
6,951,064
37
WorkingFunds
Working Fund (135)
147,415
146,305
38
TemporaryCashInvestments
Temporary Cash Investments (136)
1,220,000,000
385,000,000
39
NotesReceivable
Notes Receivable (141)
40
CustomerAccountsReceivable
Customer Accounts Receivable (142)
1,273,685,556
1,368,326,668
41
OtherAccountsReceivable
Other Accounts Receivable (143)
3,128,236,294
1,294,343,299
42
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
56,198,372
64,476,202
43
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
44
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Assoc. Companies (146)
34,585,453
21,355,991
45
FuelStock
Fuel Stock (151)
227
1,566,341
1,375,066
46
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
227
47
Residuals
Residuals (Elec) and Extracted Products (153)
227
48
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
227
442,660,412
365,624,133
49
Merchandise
Merchandise (155)
227
50
OtherMaterialsAndSupplies
Other Materials and Supplies (156)
227
51
NuclearMaterialsHeldForSale
Nuclear Materials Held for Sale (157)
202/227
52
AllowanceInventoryAndWithheld
Allowances (158.1 and 158.2)
228
396,185,501
419,851,065
53
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
228
(c)
355,147,460
(h)
195,017,512
54
StoresExpenseUndistributed
Stores Expense Undistributed (163)
227
55
GasStoredCurrent
Gas Stored Underground - Current (164.1)
108,986,991
113,465,206
56
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57
Prepayments
Prepayments (165)
305,102,547
227,100,005
58
AdvancesForGas
Advances for Gas (166-167)
59
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
3,281,579
60
RentsReceivable
Rents Receivable (172)
61
AccruedUtilityRevenues
Accrued Utility Revenues (173)
1,000,028,952
945,999,103
62
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
102,494,054
14,376,070
63
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
208,704,537
129,373,589
64
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
(d)
165,299,922
(i)
102,130,395
65
DerivativeInstrumentAssetsHedges
Derivative Instrument Assets - Hedges (176)
66
DerivativeInstrumentAssetsHedgesLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176)
67
CurrentAndAccruedAssets
Total Current and Accrued Assets (Lines 34 through 66)
7,727,233,888
4,989,381,744
68
DeferredDebitsAbstract
DEFERRED DEBITS
69
UnamortizedDebtExpense
Unamortized Debt Expenses (181)
124,158,942
131,251,529
70
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230a
71
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230b
68,809,105
3,683,889
72
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
5,845,482,579
5,018,800,793
73
PreliminarySurveyAndInvestigationCharges
Prelim. Survey and Investigation Charges (Electric) (183)
162,540
82,918
74
PreliminaryNaturalGasSurveyAndInvestigationChargesAndOtherPreliminarySurveyAndInvestigationCharges
Preliminary Natural Gas Survey and Investigation Charges 183.1)
75
OtherPreliminarySurveyAndInvestigationCharges
Other Preliminary Survey and Investigation Charges (183.2)
76
ClearingAccounts
Clearing Accounts (184)
174,950
3,237,868
77
TemporaryFacilities
Temporary Facilities (185)
78
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
26,073,137
55,551,664
79
DeferredLossesFromDispositionOfUtilityPlant
Def. Losses from Disposition of Utility Plt. (187)
80
ResearchDevelopmentAndDemonstrationExpenditures
Research, Devel. and Demonstration Expend. (188)
352
81
UnamortizedLossOnReacquiredDebt
Unamortized Loss on Reaquired Debt (189)
93,374,528
97,418,150
82
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234
(e)
5,025,590,626
1,728,161,422
83
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
84
DeferredDebits
Total Deferred Debits (lines 69 through 83)
11,183,826,407
7,038,188,233
85
AssetsAndOtherDebits
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
75,407,879,253
64,105,225,466


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: c, Value: 0
(b) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: c, Value: 0
(c) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: c, Value: 0
(d) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: c, Value: 0
(e) Concept: AccumulatedDeferredIncomeTaxes

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.

(f) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: d, Value: 0
(g) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: d, Value: 0
(h) Concept: NoncurrentPortionOfAllowances
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 53, Column: d, Value: 0
(i) Concept: DerivativeInstrumentAssetsLongTerm
Duplicate fact discrepancy. Schedule: 110 - Schedule - Comparative Balance Sheet - Assets And Other Debits, Row: 64, Column: d, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
Line No.
Title of Account
(a)
Ref. Page No.
(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
1,321,874,045
1,321,874,045
3
PreferredStockIssued
Preferred Stock Issued (204)
250
257,994,575
257,994,575
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
1,805,194,230
1,805,194,230
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
6,780,547,928
6,735,547,928
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
6,916,899
6,916,899
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254b
28,951,886
28,951,886
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118
2,884,435,643
9,712,977,993
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118
58,010,567
56,608,615
13
ReacquiredCapitalStock
(Less) Reaquired Capital Stock (217)
250
14
NoncorporateProprietorship
Noncorporate Proprietorship (Non-major only) (218)
15
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
122(a)(b)
986,708
6,290,667
16
ProprietaryCapital
Total Proprietary Capital (lines 2 through 15)
12,955,180,361
19,747,402,038
17
LongTermDebtAbstract
LONG-TERM DEBT
18
Bonds
Bonds (221)
256
18,387,100,000
18,032,100,000
19
ReacquiredBonds
(Less) Reaquired Bonds (222)
256
20
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256
21
OtherLongTermDebt
Other Long-Term Debt (224)
256
22
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
13,404,631
14,860,769
23
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
76,509,009
80,156,440
24
LongTermDebt
Total Long-Term Debt (lines 18 through 23)
18,323,995,622
17,966,804,329
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases - Noncurrent (227)
9,012,994
17,990,411
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
14,641,225,188
1,003,439,991
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
2,040,734,062
2,025,769,027
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
1,434,278,826
1,039,213,260
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
88,211,315
57,007,082
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
5,994,342,481
4,899,104,864
35
OtherNoncurrentLiabilities
Total Other Noncurrent Liabilities (lines 26 through 34)
24,207,804,866
9,042,524,635
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
NotesPayable
Notes Payable (231)
3,135,000,001
800,000,001
38
AccountsPayable
Accounts Payable (232)
2,651,188,423
2,402,987,144
39
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
40
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
38,940,769
22,050,491
41
CustomerDeposits
Customer Deposits (235)
235,799,401
231,822,866
42
TaxesAccrued
Taxes Accrued (236)
262
360,498,405
433,396,782
43
InterestAccrued
Interest Accrued (237)
234,978,351
220,498,682
44
DividendsDeclared
Dividends Declared (238)
16,235,704
2,319,386
45
MaturedLongTermDebt
Matured Long-Term Debt (239)
46
MaturedInterest
Matured Interest (240)
47
TaxCollectionsPayable
Tax Collections Payable (241)
30,123,144
34,679,077
48
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
411,182,395
692,014,936
49
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
1,682,542
12,512,046
50
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
109,769,265
88,095,705
51
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
88,211,315
57,007,082
52
DerivativeInstrumentLiabilitiesHedges
Derivative Instrument Liabilities - Hedges (245)
53
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges
54
CurrentAndAccruedLiabilities
Total Current and Accrued Liabilities (lines 37 through 53)
7,137,187,085
4,883,370,034
55
DeferredCreditsAbstract
DEFERRED CREDITS
56
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
359,612,163
423,431,367
57
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
266
108,383,883
114,033,790
58
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
59
OtherDeferredCredits
Other Deferred Credits (253)
269
227,311,425
208,094,334
60
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
(a)
3,496,782,247
3,876,105,498
61
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reaquired Debt (257)
716,895
862,920
62
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accum. Deferred Income Taxes-Accel. Amort.(281)
272
307
307
63
AccumulatedDeferredIncomeTaxesOtherProperty
Accum. Deferred Income Taxes-Other Property (282)
7,973,787,674
7,394,379,151
64
AccumulatedDeferredIncomeTaxesOther
Accum. Deferred Income Taxes-Other (283)
(b)
617,116,725
448,217,063
65
DeferredCredits
Total Deferred Credits (lines 56 through 64)
12,783,711,319
12,465,124,430
66
LiabilitiesAndOtherCredits
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
75,407,879,253
64,105,225,466


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.

(b) Concept: AccumulatedDeferredIncomeTaxesOther

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
STATEMENT OF INCOME

Quarterly

  1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
  2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
  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 column (k) the quarter to date amounts for other utility function for the current year quarter.
  4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the quarter to date amounts for other utility function for the prior year quarter.
  5. 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. Use page 122 for important notes regarding the statement of income for any account thereof.
  5. 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.
  6. 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.
  7. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
  8. Enter on page 122 a concise explanation of only those 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 appropriate dollar effect of such changes.
  9. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
  10. 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)
(Ref.) Page No.
(b)
Total Current Year to Date Balance for Quarter/Year
(c)
Total Prior Year to Date Balance for Quarter/Year
(d)
Current 3 Months Ended - Quarterly Only - No 4th Quarter
(e)
Prior 3 Months Ended - Quarterly Only - No 4th Quarter
(f)
Electric Utility Current Year to Date (in dollars)
(g)
Electric 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
Operating Revenues (400)
300
17,337,575,325
(a)
17,477,273,258
13,086,062,407
13,283,628,752
4,251,512,918
4,193,644,506
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
320
21,090,929,970
(b)
9,354,586,213
18,919,388,088
7,014,966,243
2,171,541,882
2,339,619,970
5
MaintenanceExpense
Maintenance Expenses (402)
320
1,698,634,311
1,473,178,225
1,071,056,781
959,259,070
627,577,530
513,919,155
6
DepreciationExpense
Depreciation Expense (403)
336
2,708,898,400
2,520,662,622
2,121,424,880
1,980,795,695
587,473,520
539,866,927
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336
323,697,675
332,006,690
225,407,275
237,269,411
98,290,400
94,737,279
9
AmortizationOfElectricPlantAcquisitionAdjustments
Amort. of Utility Plant Acq. Adj. (406)
336
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
2,113,770
116,111
2,113,770
116,111
11
AmortizationOfConversionExpenses
Amort. of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
629,795
629,795
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262
632,365,632
592,757,485
475,321,400
449,084,479
157,044,232
143,673,006
15
IncomeTaxesOperatingIncome
Income Taxes - Federal (409.1)
262
4,236,134
10,252,653
4,236,133
10,252,653
1
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes - Other (409.1)
262
13,470,011
108,797,147
112,005,442
105,092,246
98,535,431
3,704,901
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision for Deferred Income Taxes (410.1)
234, 272
864,342,003
208,874,972
738,531,553
275,512,268
125,810,450
66,637,296
18
ProvisionForDeferredIncomeTaxesCreditOperatingIncome
(Less) Provision for Deferred Income Taxes-Cr. (411.1)
234, 272
2,478,874,964
718,959,065
2,388,974,856
713,495,770
89,900,108
5,463,295
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adj. - Net (411.4)
266
20
GainsFromDispositionOfPlant
(Less) Gains from Disp. of Utility Plant (411.6)
580,002
13,324,707
580,002
2,517,330
10,807,377
21
LossesFromDispositionOfServiceCompanyPlant
Losses from Disp. of Utility Plant (411.7)
270,691
270,691
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 (Enter Total of lines 4 thru 24)
23,130,548,934
14,868,252,122
19,802,867,358
11,171,437,670
3,327,681,576
3,696,814,452
27
NetUtilityOperatingIncome
Net Util Oper Inc (Enter Tot line 2 less 25)
5,792,973,609
2,609,021,136
6,716,804,951
2,112,191,082
923,831,342
496,830,054
28
OtherIncomeAndDeductionsAbstract
Other Income and Deductions
29
OtherIncomeAbstract
Other Income
30
NonutilityOperatingIncomeAbstract
Nonutilty Operating Income
31
RevenuesFromMerchandisingJobbingAndContractWork
Revenues From Merchandising, Jobbing and Contract Work (415)
32
CostsAndExpensesOfMerchandisingJobbingAndContractWork
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
33
RevenuesFromNonutilityOperations
Revenues From Nonutility Operations (417)
34
ExpensesOfNonutilityOperations
(Less) Expenses of Nonutility Operations (417.1)
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
42,609
3,103,044
37
InterestAndDividendIncome
Interest and Dividend Income (419)
74,371,716
30,022,985
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
129,009,681
89,256,337
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
3,071,748
5,679,371
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
315,099
6,657,171
41
OtherIncome
TOTAL Other Income (Enter Total of lines 31 thru 40)
206,810,853
128,512,820
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
12,499,780
10,944,162
46
LifeInsurance
Life Insurance (426.2)
47
Penalties
Penalties (426.3)
5,324,520
24,386,884
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Exp. for Certain Civic, Political & Related Activities (426.4)
13,096,115
13,443,474
49
OtherDeductions
Other Deductions (426.5)
255,846,898
301,635,298
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
286,767,313
350,409,818
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262
486,744
362,370
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262
8,062,576
71,582,687
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262
29,809,600
39,875,243
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Inc. Taxes (410.2)
234, 272
33,169,360
40,539,809
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
234, 272
25,839,617
158,562,363
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adj.-Net (411.5)
5,649,907
14,378,049
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
32,098,790
181,410,407
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
112,055,250
40,486,591
61
InterestChargesAbstract
Interest Charges
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
791,084,121
806,065,887
63
AmortizationOfDebtDiscountAndExpense
Amort. of Debt Disc. and Expense (428)
29,043,258
27,416,689
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reaquired Debt (428.1)
19,003,995
18,399,376
65
AmortizationOfPremiumOnDebtCredit
(Less) Amort. of Premium on Debt-Credit (429)
818,824
1,963,283
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
146,025
146,025
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Assoc. Companies (430)
68
OtherInterestExpense
Other Interest Expense (431)
127,444,511
65,165,469
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
52,532,426
37,674,326
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
913,078,610
877,263,787
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
6,818,107,469
1,691,270,758
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
77
ExtraordinaryItemsAfterTaxes
Extraordinary Items After Taxes (line 75 less line 76)
78
NetIncomeLoss
Net Income (Total of line 71 and 77)
6,818,107,469
1,691,270,758


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OperatingRevenues

 

Includes interdepartmental operating revenues in Line 2 and

 

operations expenses in Line 4 for the twelve-month period ended December 31:

 

 

 

 

 

 

 

2018

2017

 

 

 

Revenues

Expenses

Revenues

Expenses

 

Electric

46,634,494

81,028,298

44,421,522

71,545,053

 

Gas

208,166,556

173,772,752

189,093,175

161,969,645

 

Total

254,801,050

254,801,050

233,514,697

233,514,697

 

 

(b) Concept: OperationExpense

Refer to the footnote for Line 2, column c.

(c) Concept: OperatingRevenues

Line 2,

Includes interdepartmental operating revenues in Line 2 and

Col e

operations expenses in Line 4 for the three-month period ended December 31:

 

 

 

 

 

 

 

 

Current QTR

Prior QTR

 

 

Revenues

Expenses

Revenues

Expenses

 

Electric

16,865,517

29,006,393

15,870,676

25,298,077

 

Gas

70,074,831

57,933,955

64,403,078

54,975,679

 

Total

86,940,348

86,940,348

80,273,754

80,273,754

(d) Concept: OperationExpense

Refer to the footnote for Line 2, column e.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report


End of:
2018
/
Q4
STATEMENT OF RETAINED EARNINGS
  1. Do not report Lines 49-53 on the quarterly report.
  2. Report all changes in appropriated retained earnings, unappropriated retained earnings, and unappropriated undistributed subsidiary earnings for the year.
  3. 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).
  4. State the purpose and amount for each reservation or appropriation of retained earnings.
  5. 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.
  6. Show dividends for each class and series of capital stock.
  7. Show separately the State and Federal income tax effect of items shown for Account 439, Adjustments to Retained Earnings.
  8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
  9. If any notes appearing in the report to stockholders are applicable to this statement, attach them at page 122-123.
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 (Account 216)
1
UnappropriatedRetainedEarnings
Balance-Beginning of Period
9,450,613,073
8,576,546,935
2
ChangesAbstract
Changes
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
4
AdjustmentsToRetainedEarningsCreditAbstract
Adjustments to Retained Earnings Credit
4.1
AdjustmentsToRetainedEarningsCredit
4.2
AdjustmentsToRetainedEarningsCredit
Reclassify stranded tax effects resulting from the 2017 Tax Cuts
4.3
AdjustmentsToRetainedEarningsCredit
and Jobs Act from Accumulated Other Comprehensive Income
2,079,484
4.4
AdjustmentsToRetainedEarningsCredit
4.5
AdjustmentsToRetainedEarningsCredit
4.6
AdjustmentsToRetainedEarningsCredit
4.7
AdjustmentsToRetainedEarningsCredit
4.8
AdjustmentsToRetainedEarningsCredit
4.9
AdjustmentsToRetainedEarningsCredit
4.10
AdjustmentsToRetainedEarningsCredit
9
AdjustmentsToRetainedEarningsCredit
TOTAL Credits to Retained Earnings (Acct. 439)
2,079,484
10
AdjustmentsToRetainedEarningsDebitAbstract
Adjustments to Retained Earnings Debit
10.1
AdjustmentsToRetainedEarningsDebit
10.2
AdjustmentsToRetainedEarningsDebit
10.3
AdjustmentsToRetainedEarningsDebit
10.4
AdjustmentsToRetainedEarningsDebit
10.5
AdjustmentsToRetainedEarningsDebit
10.6
AdjustmentsToRetainedEarningsDebit
10.7
AdjustmentsToRetainedEarningsDebit
10.8
AdjustmentsToRetainedEarningsDebit
10.9
AdjustmentsToRetainedEarningsDebit
10.10
AdjustmentsToRetainedEarningsDebit
15
AdjustmentsToRetainedEarningsDebit
TOTAL Debits to Retained Earnings (Acct. 439)
16
BalanceTransferredFromIncome
Balance Transferred from Income (Account 433 less Account 418.1)
6,818,150,078
1,694,373,802
17
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Acct. 436)
17.1
AppropriationsOfRetainedEarnings
17.2
AppropriationsOfRetainedEarnings
Reserves for excess earnings on FERC hydroelectric
17.3
AppropriationsOfRetainedEarnings
project licenses pursuant to Federal Power Act Section 10 (d)
23,656,015
23,778,373
17.4
AppropriationsOfRetainedEarnings
22
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Acct. 436)
23,656,015
23,778,373
23
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
23.1
DividendsDeclaredPreferredStock
23.2
DividendsDeclaredPreferredStock
Preferred Dividends Declared
(b)
13,916,352
23.3
DividendsDeclaredPreferredStock
23.4
DividendsDeclaredPreferredStock
Accrued Preferred Dividends Requirement
(a)
13,916,318
23.5
DividendsDeclaredPreferredStock
29
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
13,916,318
13,916,352
30
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
30.1
DividendsDeclaredCommonStock
30.2
DividendsDeclaredCommonStock
Common Stock Dividends Declared
(c)
784,000,000
30.3
DividendsDeclaredCommonStock
30.4
DividendsDeclaredCommonStock
30.5
DividendsDeclaredCommonStock
36
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Acct. 438)
784,000,000
37
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
1,444,562
1,387,061
38
UnappropriatedRetainedEarnings
Balance - End of Period (Total 1,9,15,16,22,29,36,37)
2,598,414,708
9,450,613,073
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
.1
AppropriatedRetainedEarnings
.2
AppropriatedRetainedEarnings
.3
AppropriatedRetainedEarnings
.4
AppropriatedRetainedEarnings
Reserves for excess earnings on FERC hydroelectric
.5
AppropriatedRetainedEarnings
project licenses pursuant to Federal Power Act Section 10 (d)
.6
AppropriatedRetainedEarnings
.7
AppropriatedRetainedEarnings
.8
AppropriatedRetainedEarnings
.9
AppropriatedRetainedEarnings
.10
AppropriatedRetainedEarnings
.11
AppropriatedRetainedEarnings
.12
AppropriatedRetainedEarnings
.13
AppropriatedRetainedEarnings
.14
AppropriatedRetainedEarnings
45
AppropriatedRetainedEarnings
TOTAL Appropriated Retained Earnings (Account 215)
23,656,015
23,778,373
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
262,364,920
238,586,547
47
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
286,020,935
262,364,920
48
RetainedEarnings
TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
2,884,435,643
9,712,977,993
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
56,608,615
52,118,510
50
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
42,609
3,103,044
51
DividendsReceived
(Less) Dividends Received (Debit)
52
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
1,444,561
1,387,061
52.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
Utility subsidiary earnings reflected in operations and maintenance accounts (offset in 216)
53
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year (Total lines 49 thru 52)
58,010,567
56,608,615


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report


End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DividendsDeclaredPreferredStock

There were no preferred dividends declared for the period ended December 31, 2018.

 

However, since preferred stocks are cumulative, preferred dividend accruals were recorded. The liability is shown in Line 44, Dividends Declared, on page 112 of the balance sheet.

 

The following is the detail of accrued dividends on First Preferred Stocks for the period ended December 31, 2018:

 

 

Annual

No. of Dividends Total

Class of Stock Shares Per Share Accrued

 

6.00% Cumulative, Non-Redeemable 4,211,662 $1.500 $ 6,317,492

5.50% Cumulative, Non-Redeemable 1,173,163 1.375 1,613,099

5.00% Cumulative, Non-Redeemable 400,000 1.250 500,000

5.00% Cumulative, Redeemable 1,778,172 1.250 2,222,715

5.00% Cumulative, Redeemable - Series A 934,322 1.250 1,167,903

4.80% Cumulative, Redeemable 793,031 1.200 951,637

4.50% Cumulative, Redeemable 611,142 1.125 687,535

4.36% Cumulative, Redeemable 418,291 1.090 455,937

-----------

Total $13,916,318

===========

 

(b) Concept: DividendsDeclaredPreferredStock

The following is the detail of dividends declared on First Preferred Stocks

for the year ended December 31, 2017:

 

 

Annual

No. of Dividends Total

Class of Stock Shares Per Share Declared

 

6.00% Cumulative, Non-Redeemable 4,211,662 $1.500 $ 6,317,510

5.50% Cumulative, Non-Redeemable 1,173,163 1.375 1,613,105

5.00% Cumulative, Non-Redeemable 400,000 1.250 500,000

5.00% Cumulative, Redeemable 1,778,172 1.250 2,222,718

5.00% Cumulative, Redeemable - Series A 934,322 1.250 1,167,907

4.80% Cumulative, Redeemable 793,031 1.200 951,637

4.50% Cumulative, Redeemable 611,142 1.125 687,537

4.36% Cumulative, Redeemable 418,291 1.090 455,938

-----------

Total $13,916,352

===========

 

 

 

(c) Concept: DividendsDeclaredCommonStock

This represents dividends declared on Common Stock to PG&E Corporation for the

year ended December 31, 2017.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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 31) 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 No.1 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 117)
6,818,107,469
1,691,270,758
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
3,034,709,845
2,852,785,423
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Disallowed Capital Expenditures
(a)
44,798,404
47,398,938
5.2
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Unamortized Loss or Gain on Reacquired Debt
18,857,970
17,613,914
5.3
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Expenses, Discount and Premium - Long Term Debt
19,699,655
18,098,551
8
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
2,538,903,619
1,083,992,255
9
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustment (Net)
5,649,907
14,378,049
10
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(b)
1,853,762,002
(r)
39,678,174
11
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(c)
72,749,339
(s)
16,973,849
12
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
13
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
348,769,957
505,815,231
14
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
715,545,561
(t)
981,763,074
15
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
16,151,084
609,750,902
16
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
129,009,681
89,256,337
17
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
1,401,952
4,490,105
18
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other (provide details in footnote):
18.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Other (provide details in footnote):
(e)
13,476,022,102
(u)
129,518,306
22
NetCashFlowFromOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
4,704,784,415
5,898,041,248
24
CashFlowsFromInvestmentActivitiesAbstract
Cash Flows from Investment Activities:
25
ConstructionAndAcquisitionOfPlantIncludingLandAbstract
Construction and Acquisition of Plant (including land):
26
GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Gross Additions to Utility Plant (less nuclear fuel)
(f)
6,564,592,641
(v)
5,596,719,659
27
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
(g)
78,340,868
(w)
131,760,000
28
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
29
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
30
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(h)
129,009,681
(x)
89,256,337
31
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other (provide details in footnote):
34
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 26 thru 33)
(i)
6,513,923,828
(y)
5,639,223,322
36
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
37
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
22,233,335
25,953,577
39
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Assoc. and Subsidiary Companies
(j)
1,611,620
(z)
3,512,324
40
ContributionsAndAdvancesFromAssociatedAndSubsidiaryCompanies
Contributions and Advances from Assoc. and Subsidiary Companies
41
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompaniesAbstract
Disposition of Investments in (and Advances to)
42
DispositionOfInvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Disposition of Investments in (and Advances to) Associated and Subsidiary Companies
44
PurchaseOfInvestmentSecurities
Purchase of Investment Securities (a)
45
ProceedsFromSalesOfInvestmentSecurities
Proceeds from Sales of Investment Securities (a)
46
LoansMadeOrPurchased
Loans Made or Purchased
47
CollectionsOnLoans
Collections on Loans
49
NetIncreaseDecreaseInReceivablesInvestingActivities
Net (Increase) Decrease in Receivables
50
NetIncreaseDecreaseInInventoryInvestingActivities
Net (Increase) Decrease in Inventory
51
NetIncreaseDecreaseInAllowancesHeldForSpeculationInvestingActivities
Net (Increase) Decrease in Allowances Held for Speculation
52
NetIncreaseDecreaseInPayablesAndAccruedExpensesInvestingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
53
OtherAdjustmentsToCashFlowsFromInvestmentActivities
Other (provide details in footnote):
53.1
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Payments to Advances by Assoc. and Subsidiary Companies
3,253,555
53.2
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Net (Increase) Decrease in Restricted Cash
53.3
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Proceeds from nuclear decommissioning trust investments
1,411,689,770
1,291,749,504
53.4
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Purchases of nuclear decommissioning trust investments and other
(k)
1,484,791,279
(ab)
1,322,693,283
57
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
6,566,403,622
5,650,979,403
59
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
60
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
61
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Long-Term Debt (b)
792,991,500
2,713,526,928
62
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Preferred Stock
63
ProceedsFromIssuanceOfCommonStockFinancingActivities
Common Stock
64
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other (provide details in footnote):
66
NetIncreaseInShortTermDebt
Net Increase in Short-Term Debt (c)
2,334,796,430
221,734,268
67
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
67.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Equity contribution from PG&E Corporation
45,000,000
455,000,000
70
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total 61 thru 69)
3,172,787,930
2,946,792,660
72
PaymentsForRetirementAbstract
Payments for Retirement of:
73
PaymentsForRetirementOfLongTermDebtFinancingActivities
Long-term Debt (b)
(l)
445,000,000
(ac)
1,445,000,000
74
PaymentsForRetirementOfPreferredStockFinancingActivities
Preferred Stock
75
PaymentsForRetirementOfCommonStockFinancingActivities
Common Stock
76
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Customer Advances for Construction
(m)
4,227,505
(ad)
7,963,753
76.2
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Other
(n)(o)
21,850,462
(ae)(af)
68,324,365
78
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
(ag)
500,000,000
80
DividendsOnPreferredStock
Dividends on Preferred Stock
13,916,352
81
DividendsOnCommonStock
Dividends on Common Stock
784,000,000
83
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
2,710,164,973
127,588,190
85
NetIncreaseDecreaseInCashAndCashEquivalentsAbstract
Net Increase (Decrease) in Cash and Cash Equivalents
86
NetIncreaseDecreaseInCashAndCashEquivalents
Net Increase (Decrease) in Cash and Cash Equivalents (Total of line 22, 57 and 83)
848,545,766
374,650,035
88
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
(p)
449,815,658
(ah)
75,165,623
90
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
(q)
1,298,361,424
(ai)
449,815,658


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NoncashAdjustmentsToCashFlowsFromOperatingActivities

This primarily consists of a $14M true-up of the PSEP Plant reserve and a $41M true-up of the TIMP Plant reserve based on the 2018 forecast, offset by the Accumulated depreciation impacts and additional write-offs.

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -1853762002
(c) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -72749339
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -715545561
(e) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

This consists of the following:

 

2018 2017

 

(Increase) Decrease in Other Working Capital $ (438,463,686) $ 105,668,533

Increase (Decrease) - Other Noncurrent Liabilities* 13,777,892,530 (191,024,518) Others

Nuclear Fuel Lease Amortization 125,886,537 123,258,253

Payment on capital lease obligation (1,921,000) (18,262,296)

Collateral Adjustment 12,592,010 (13,675,915)

Bad Debt Expense 35,471,842 54,533,182

Tax benefit on stock option exercises (shortfall) (11,642,424) 24,464,196

Other-net** (23,793,706) 44,556,871 --------------- ---------------

Total $ 13,476,022,103 $ 129,518,306

=============== ===============

 

*This primarily consists of a $14 billion increase to the "Accumulated Provision" balances (accounts 228.2, 228.3, 228.4 and 229) corresponding to the amount charged for the lower end of the range of the Utility's reasonably estimated losses related to the 2017 Northern California wildfires and the 2018 Camp fire. This increase is partially offset by $109 million of asset retirement obligation work performed.

 

**This primarily consists of allowances related to GHG.

(f) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -6564592641
(g) Concept: GrossAdditionsToNuclearFuelInvestingActivities
Original value: -78340868
(h) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -129009681
(i) Concept: CashOutflowsForPlant
Original value: -6513923828
(j) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -1611620
(k) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

"Other" amounts presented on this line consist of the following:

 

2018 2017

 

Purchases of Nuclear Decommissioning

Trust Investments $ (1,484,791,279) $ (1,322,771,298)

Decrease in other investments - 78,015

---------------- ----------------

Total $ (1,484,791,279) $ (1,322,693,283)

================ ================

(l) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -445000000
(m) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: 4227505
(n) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -21850462
(o) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

This consists of the following:

 

2018 2017

 

Increase (Decrease) in customer deposits $ 3,903,352 $ 469,325

Debt Issuance Costs - ST Borrowings (25,000) (3,268,176)

Employee taxes paid for withheld shares (10,580,685) (65,525,514)

Premium paid for early redemption of long-term debt (15,148,129) -------------- --------------

Total $ (21,850,462) $ (68,324,365) ============== ==============

(p) Concept: CashAndCashEquivalents

See footnote in column (b), Line 90.

(q) Concept: CashAndCashEquivalents

This consists of the following:

 

2018 2017

 

Cash (131) $ 71,327,413 $ 57,718,289

Special Deposits (132-134)* 6,886,597 6,951,064

Working Funds (135) 147,415 146,305

Temporary Cash Investment (136) 1,220,000,000 385,000,000

-------------- --------------

Total $1,298,361,425 $ 449,815,658

============== ==============

 

 

Supplemental disclosures of cash flow information (in millions):

 

Cash paid for:

Interest (net of amounts capitalized) $ (773) $ (781) Income taxes paid (refunded), net (59) 162

 

Supplemental disclosures of noncash

investing and financing activities:

 

Capital expenditures financed through

accounts payable 368 501

 

 

*Per ASU 2016-18, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows. See footnote in column (c), line 48 for further discussion.

(r) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: 39678174
(s) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -16973849
(t) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -981763074
(u) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivities

See footnote in column (b), Line 18.

(v) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -5596719659
(w) Concept: GrossAdditionsToNuclearFuelInvestingActivities
Original value: -131760000
(x) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -89256337
(y) Concept: CashOutflowsForPlant
Original value: -5639223322
(z) Concept: InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Original value: -3512324
(aa) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows. Previously, changes in restricted cash were reported within cash flows from investing activities. The Utility applied the requirements on a retrospective basis when the ASU became effective on January 1, 2018.

The retrospective adjustments to the Statement of Cash Flows for the Utility resulted in an increase to Net cash used in investing activities of $186,641, an increase to Cash and cash equivalents at January 1 by $6,764,423, and an increase to Cash, cash equivalents and restricted cash at December 31 by $6,951,064 for the year ended December 31, 2017.

(ab) Concept: OtherAdjustmentsToCashFlowsFromInvestmentActivities

See footnote in column (b), Line 55.

(ac) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -1445000000
(ad) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -7963753
(ae) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities

See footnote in column (b), Line 79.

(af) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -68324365
(ag) Concept: NetDecreaseInShortTermDebt
Original value: -500000000
(ah) Concept: CashAndCashEquivalents

This amount has been adjusted to reflect the retrospective adjustment for ASU 2016-18. See footnote in column (c), line 48 for additional discussion.

(ai) Concept: CashAndCashEquivalents

See footnote in column (b), Line 90.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
NOTES TO FINANCIAL STATEMENTS
  1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement.
  2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock.
  3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof.
  4. Where Accounts 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 items. See General Instruction 17 of the Uniform System of Accounts.
  5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions.
  6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
  7. 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.
  8. 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.
  9. 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.

Introduction:

 

The notes below are excerpts from PG&E Corporation and the Utility’s combined Report on Form 10-K for the year ended December 31, 2018, as filed with the Securities and Exchange Commission (“SEC”) on February 28, 2019.  The following disclosures contain information in accordance with SEC reporting requirements.  As such, due to the differences between FERC and SEC reporting requirements, certain amounts disclosed in the following notes may not agree to balances in the FERC financial statements.

 

The accompanying financial statements were prepared in accordance with the accounting requirements of the Federal Energy Regulatory Commission (“FERC”) as set forth in its applicable Uniform System of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America (“GAAP”).  The primary differences from the Utility’s GAAP basis financial statements as presented in the Form 3-Q are that (1) subsidiaries are not consolidated and are shown under the equity method of accounting, (2) deferred income tax assets and liabilities are not offset against each other but are shown as separate items on the balance sheet, are long-term, and exclude the impact of uncertain temporary tax positions, (3) cost of removal is reported in accumulated depreciation for FERC reporting purposes (GAAP requires that cost of removal be classified as a regulatory liability), (4) there is no current liability classification of the current portion of long-term debt for FERC reporting, (5) there is no reclassification of balancing accounts from current assets to current liabilities for FERC reporting, (6) interdepartmental revenues and expenses between electric and gas operations of the Utility are not eliminated for FERC reporting, (7) penalties and disallowances are reported in other income deductions for FERC reporting, and (8) payments on capital lease obligations are disclosed in operating activities in the statement of cash flows, (9) debt issuance costs are not deducted from the carrying amount of that debt liability for FERC reporting, (10) there is no current liability classification of the current portion of accumulated provision for injuries and damages for FERC reporting, and (11) FERC reporting does not reclass non-service costs related to pension benefits on the income statement pursuant to ASU 2017-07.

 

Subsequent Events:

 

On January 16, 2019 the FERC approved the use of Account 439 (Docket No. AC19-19-000), Adjustments to Retained Earnings, to record a cumulative-effect adjustment to retained earnings in order to address the stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017 (Tax Cuts and Jobs Act), and to implement Accounting Standards Update (ASU) No. 2018-02.2. PG&E Corporation and the Utility elected to adopt this treatment as of December 31, 2018.

 

Management has evaluated the impact of events occurring after December 31, 2018 up to February 28, 2019, the date that

Pacific Gas and Electric Company’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 16, 2019. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.

 

Energy Storage Assets (FERC Order No. 784):

 

The following disclosure has been included to comply with accounting and reporting guidance issued by the FERC for new electric storage technologies as a result of FERC Order No. 784.

 

Energy Plant Account

 

Energy storage assets totaled $32,142,500 at December 31, 2018, all of which is recorded in account 363 in accordance with FERC Order No. 784.

 

Power Purchased Account

 

Energy storage-related purchased power costs totaled ($220,207) for the year ended December 31, 2018, all of which is recorded in account 555.1 in accordance with FERC Order No. 784.

 

Operation and Maintenance Expense Accounts

 

Energy storage-related operating expenses totaled $0 for the year ended December 31, 2018, of which $0 is recorded in account 582 and $0 is recorded in account 588.  Amounts associated with distribution functional use would have been recorded in account 584.1 and amounts associated with production functional use would have been recorded in account 548.1, in accordance with FERC Order No. 784. Please see table below.

 

Energy storage-related maintenance expenses totaled $185,192 for the year ended December 31, 2018, of which $0 is recorded in account 570 and $185,192 is recorded in account 592.  Amounts associated with distribution functional use would have been recorded in account 592.2 and amounts associated with production functional use would have been recorded in account 553.1, in accordance with FERC Order No. 784. Please see table below.

 

Other Expense Accounts

 

Energy storage-related employee pension and benefits expenses are recorded in account 926 in the amount of $0.

 

Energy storage-related payroll tax expenses are recorded in account 408.1 in the amount of $0.   

 

The following information to be reported in the newly adopted schedule pages 419-420 can be submitted as part of pages 122-123:

 

Energy Storage Operations (Small Plants)

Line no.

Name of Energy Storage Project

Functional classification

Location of the Project

Project Cost

Operations (Excluding Fuel used in Storage Operations)

Maintenance

Cost of fuel used in storage operations

Account No. 555.1, Power Purchased for Storage Operations

Other Expenses

1

Vaca-Dixon

Production

 

Vacaville, CA

$11,286,007

 

$0

 

 

$70,271

 

$0

($220,207)

 

 

$0

2

Hitachi

Distribution

San Jose, CA

$20,856,493

 

$0

 

$96,323

 

$0

$0

$0

 

3

Browns Valley

Distribution

Marysville, CA

$0

$0

$18,598

$0

$0

$0

Totals

$32,142,500

$0

$185,192

 

$0

($220,207)

 

$0

 

 

Accumulated Deferred Income Taxes:

 

The Tax Cuts and Jobs Act of 2017 (“the Tax Act”) reduced the federal income tax rate from 35% to 21% beginning on January 1, 2018. The reduction in tax rate caused a remeasurement of deferred tax assets and liabilities by $4.5 billion comprising of $1.6 billion reduction in flow through net excess deferred tax liabilities and $2.9 billion reduction in normalized net excess deferred tax liabilities. Based on the estimate of the amount of excess deferred taxes expected to reduce future customer rates, the Utility recorded an increase in regulatory liabilities of approximately $5.6 billion, which includes the $4.5 billion reduction in net excess deferred tax liabilities and an additional $1.1 billion in regulatory liabilities representing revenue reduction due to customers for previously collected income taxes. The Utility also recorded a $1.1 billion deferred tax asset related to the regulatory liability.

 

The following table shows the results of the remeasurement of excess deferred income taxes in 2017 and the FERC accounts affected:

 

Increase/(Decrease) - in millions

 

 

 

Jurisdiction

Account 254

Account 190

Account 282

Account 283

FERC

$1,283

$(189)

$(1,472)

-

CPUC

4,294

(492)

(4,767)

(19)

Total

$5,577

$(681)

$(6,239)

$(19)

 

 

The following table summarizes the amount of excess deferred income taxes that is considered protected and unprotected as of December 31, 2018 and 2017. Excess deferred income taxes have been amortized in Accounts 401.1 and 411.1 in 2018.

 

In millions

Jurisdiction

12/31/2018

12/31/2017

Amortization Period

FERC - Protected

$753

$766

Regulated book life of the underlying plant - 15 to 75 years

FERC - Unprotected

156

158

Subject to approval

Total – FERC

$909

$924

 

 

 

 

 

CPUC - Protected

$2,684

$2,765

 

CPUC - Unprotected

(799)

(820)

Regulated book life of the underlying plant -5 to 120 years

Total - CPUC

$1,855

$1,945

Subject to approval

 

 

 

 

Total

$2,794

$2,869

 

 

The Utility filed the estimated revenue impact of the Tax Act with the CPUC and FERC in 2018. The Utility has not received final regulatory decisions as of December 31, 2018


 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

 

NOTE 1: ORGANIZATION AND BASIS OF PRESENTATION

 

Organization and Basis of Presentation

 

PG&E Corporation is a holding company whose primary operating subsidiary is Pacific Gas and Electric Company, a public utility serving northern and central California. The Utility generates revenues mainly through the sale and delivery of electricity and natural gas to customers. The Utility is primarily regulated by the CPUC and the FERC. In addition, the NRC oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

 

This is a combined annual report of PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. All intercompany transactions have been eliminated in consolidation. The Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation and the Utility assess financial performance and allocate resources on a consolidated basis (i.e., the companies operate in one segment).

 

The accompanying Consolidated Financial Statements have been prepared in conformity with GAAP and in accordance with the reporting requirements of Form 10-K. The preparation of financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Some of the more significant estimates and assumptions relate to the Utility’s wildfire-related liabilities, legal and regulatory contingencies, environmental remediation liabilities, insurance receivables, regulatory assets and liabilities, AROs, and pension and other postretirement benefit plans obligations. Management believes that its estimates and assumptions reflected in the Consolidated Financial Statements are appropriate and reasonable. A change in management’s estimates or assumptions could result in an adjustment that could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows during the period in which such change occurred.

 

Chapter 11 Filing and Going Concern

 

The accompanying Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the continuity of operations, the realization of assets and the satisfaction of liabilities in the normal course of business. However, as a result of the challenges that are further described below, such realization of assets and satisfaction of liabilities are subject to uncertainty. PG&E Corporation and the Utility are facing extraordinary challenges relating to a series of catastrophic wildfires that occurred in Northern California in 2017 and 2018.  See Note 13 below. Uncertainty regarding these matters raises substantial doubt about PG&E Corporation's and the Utility's abilities to continue as going concerns.  PG&E Corporation and the Utility have determined that commencing reorganization cases under Chapter 11 is necessary to restore PG&E Corporation's and the Utility's financial stability to fund ongoing operations and provide safe service to customers. However, there can be no assurance that such proceedings will restore PG&E Corporation's and the Utility's financial stability.  On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court.  See Note 15 below.  The Consolidated Financial Statements do not include any adjustments that might be necessary should PG&E Corporation and the Utility be unable to continue as going concerns.

 

Pursuant to Chapter 11, PG&E Corporation and the Utility retain control of their assets and are authorized to operate their business as debtors in possession while being subject to the jurisdiction of the Bankruptcy Court. While operating as debtors in possession under Chapter 11, PG&E Corporation and the Utility may sell or otherwise dispose of or liquidate assets or settle liabilities, subject to the approval of the Bankruptcy Court or as otherwise permitted in the ordinary course of business and subject to restrictions in PG&E Corporation's and the Utility's DIP Credit Agreement (see Note 4 and Note 15 below) and applicable orders of the Bankruptcy Court, for amounts other than those reflected in the accompanying Consolidated Financial Statements.  Any such actions occurring during the Chapter 11 Cases confirmed by the Bankruptcy Court could materially impact the amounts and classifications of assets and liabilities reported in PG&E Corporation's and the Utility's Consolidated Financial Statements.

 

NOTE 2: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Loss Contingencies

 

A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can reasonably be estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation’s and the Utility’s provision for loss and expense excludes anticipated legal costs, which are expensed as incurred.

 

Regulation and Regulated Operations

 

The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service.  The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales.  The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities.  The Utility capitalizes and records, as regulatory assets, costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered in future rates.  Regulatory assets are amortized over the future periods in which the costs are recovered.  If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities.  Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

 

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.  In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund.  These differences have no impact on net income.  See “Revenue Recognition” below.

 

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable.  To the extent that portions of the Utility’s operations cease to be subject to cost of service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

 

Revenue Recognition

 

Revenue from Contracts with Customers

 

The Utility recognizes revenues when electricity and natural gas services are delivered.  The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period.  Unbilled revenues are included in accounts receivable on the Consolidated Balance Sheets.  Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

 

The FERC authorizes the Utility’s revenue requirements in periodic TO rate cases.  The Utility’s ability to recover revenue requirements authorized by the FERC is dependent on the volume of the Utility’s electricity sales, and revenue is recognized only for amounts billed and unbilled, net of a reserve for revenues subject to refund.

 

Regulatory Balancing Account Revenue

 

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRC and its GT&S rate cases, which generally occur every three or four years.  The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months.  Generally, electric and natural gas operating revenue is recognized ratably over the year.

 

The CPUC also has authorized the Utility to collect additional revenue requirements to recover costs that the Utility has been authorized to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs.  In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.

 

The following table presents the Utility’s revenues disaggregated by type of customer:

(in millions)

Year Ended December 31, 2018

Electric

 

Revenue from contracts with customers

 

Residential

$

5,051

 

Commercial

4,908

 

Industrial

1,532

 

Agricultural

1,234

 

Public street and highway lighting

72

 

Other (1)

(720

)

Total revenue from contracts with customers - electric

12,077

 

Regulatory balancing accounts (2)

636

 

Total electric operating revenue

$

12,713

 

 

 

Natural gas

 

Revenue from contracts with customers

 

Residential

$

2,042

 

Commercial

537

 

Transportation service only

1,151

 

Other (1)

75

 

Total revenue from contracts with customers - gas

3,805

 

Regulatory balancing accounts (2)

242

 

Total natural gas operating revenue

4,047

 

Total operating revenues

$

16,760

 

 

 

(1) This activity is primarily related to the change in unbilled revenue and amounts subject to refund, partially offset by other miscellaneous revenue items.

(2) These amounts represent revenues authorized to be billed or refunded to customers.

 

Cash and Cash Equivalents

 

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less.  Cash equivalents are stated at fair value.

 

Allowance for Doubtful Accounts Receivable

 

PG&E Corporation and the Utility recognize an allowance for doubtful accounts to record uncollectable customer accounts receivable at estimated net realizable value.  The allowance is determined based upon a variety of factors, including historical write-off experience, aging of receivables, current economic conditions, and assessment of customer collectability.

 

Inventories

 

Inventories are carried at weighted-average cost and include natural gas stored underground as well as materials and supplies.  Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation.  Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.

 

Emission Allowances

 

The Utility purchases GHG emission allowances to satisfy its compliance obligations.  Associated costs are recorded as inventory and included in current assets – other and other noncurrent assets – other on the Consolidated Balance Sheets.  Costs are carried at weighted-average and are recoverable through rates.

 

Property, Plant, and Equipment

 

Property, plant, and equipment are reported at the lower of their historical cost less accumulated depreciation or fair value.  Historical costs include labor and materials, construction overhead, and AFUDC.  (See “AFUDC” below.)  The Utility’s total estimated useful lives and balances of its property, plant, and equipment were as follows:

 

Estimated Useful

 

Balance at December 31,

(in millions, except estimated useful lives)

Lives (years)

 

2018

 

2017

Electricity generating facilities (1)

5 to 120

 

$

13,047

 

 

$

11,843

 

Electricity distribution facilities

15 to 65

 

32,926

 

 

31,110

 

Electricity transmission facilities

15 to 75

 

13,177

 

 

12,180

 

Natural gas distribution facilities

20 to 60

 

13,296

 

 

12,312

 

Natural gas transmission and storage facilities

5 to 62

 

8,260

 

 

7,329

 

Construction work in progress

 

 

2,564

 

 

2,471

 

Total property, plant, and equipment

 

 

83,270

 

 

77,245

 

Accumulated depreciation

 

 

(24,713

)

 

(23,456

)

Net property, plant, and equipment

 

 

$

58,557

 

 

$

53,789

 

 

 

 

 

 

 

(1) Balance includes nuclear fuel inventories.  Stored nuclear fuel inventory is stated at weighted-average cost.  Nuclear fuel in the reactor is expensed as it is used based on the amount of energy output.  (See Note 14 below.)

 

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property.  This method approximates the straight line method of depreciation over the useful lives of property, plant, and equipment.  The Utility’s composite depreciation rates were 3.82% in 2018, 3.83% in 2017, and 3.73% in 2016.  The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers.  Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement.  Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation.  The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to operating and maintenance expense as incurred.

 

AFUDC

 

AFUDC represents the estimated costs of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction.  AFUDC is recoverable from customers through rates over the life of the related property once the property is placed in service.  AFUDC related to the cost of debt is recorded as a reduction to interest expense.  AFUDC related to the cost of equity is recorded in other income.  The Utility recorded AFUDC related to debt and equity, respectively, of $53 million and $129 million during 2018, $38 million and $89 million during 2017, and $51 million and $112 million during 2016.

 

Asset Retirement Obligations

 

The following table summarizes the changes in ARO liability during 2018 and 2017, including nuclear decommissioning obligations:

(in millions)

2018

 

2017

ARO liability at beginning of year

$

4,899

 

 

$

4,684

 

Revision in estimated cash flows

993

 

 

128

 

Accretion

211

 

 

207

 

Liabilities settled

(109

)

 

(120

)

ARO liability at end of year

$

5,994

 

 

$

4,899

 

 

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity.  As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made.  As such, ARO liabilities are not recorded for retirement activities associated with substations, photovoltaic facilities, and certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

 

Nuclear Decommissioning Obligation

 

Detailed studies of the cost to decommission the Utility’s nuclear generation facilities are generally conducted every three years in conjunction with the Nuclear Decommissioning Cost Triennial Proceeding conducted by the CPUC.  In December 2018, the Utility submitted its updated decommissioning cost estimate to the CPUC and correspondingly increased its ARO liabilities by $1.1 billion.  The adjustment was a result of increased estimated costs based on a site-specific decommissioning analysis.  The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants.  Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment.  The Utility recovers its revenue requirements for decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

 

The total nuclear decommissioning obligation accrued was $4.7 billion and $3.5 billion at December 31, 2018 and 2017, respectively.  The estimated undiscounted nuclear decommissioning cost for the Utility’s nuclear power plants was $10.6 billion and $7.0 billion at December 31, 2018 and 2017, respectively.

 

Disallowance of Plant Costs

 

PG&E Corporation and the Utility record a charge when it is both probable that costs incurred or projected to be incurred for recently completed plant will not be recoverable through rates charged to customers and the amount of disallowance can be reasonably estimated.  See “Enforcement and Litigation Matters” in Note 14 below.

 

Nuclear Decommissioning Trusts

 

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and one retired facility at Humboldt Bay.  Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use.  The Utility's nuclear decommissioning costs are recovered from customers through rates and are held in trusts until authorized for release by the CPUC.

 

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion.  Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable or recoverable, respectively, from customers through rates.  Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO.  There is no impact on the Utility’s earnings or accumulated other comprehensive income.  The cost of debt and equity securities sold by the trust is determined by specific identification.

 

Variable Interest Entities

 

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest.  An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

 

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs.  Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility.  To determine whether the Utility was the primary beneficiary of any of these VIEs at December 31, 2018, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights and operating and maintenance activities.  The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity.  The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs.  Since the Utility was not the primary beneficiary of any of these VIEs at December 31, 2018, it did not consolidate any of them.

 

Other Accounting Policies

 

For other accounting policies impacting PG&E Corporation’s and the Utility’s consolidated financial statements, see “Income Taxes” in Note 8, “Derivatives” in Note 9, “Fair Value Measurements” in Note 10, and “Contingencies and Commitments” in Notes 13 and 14 herein.

 

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income

 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2018 consisted of the following:

(in millions, net of income tax)

Pension

Benefits

 

Other

Benefits

 

Total

Beginning balance

$

(25

)

 

$

17

 

 

$

(8

)

Other comprehensive income before reclassifications:

 

 

 

 

 

Unrecognized net actuarial loss (net of taxes of $41 and $9, respectively)

(104

)

 

(23

)

 

(127

)

Regulatory account transfer (net of taxes of $41 and $9, respectively)

107

 

 

23

 

 

130

 

Amounts reclassified from other comprehensive income:

 

 

 

 

 

Amortization of prior service cost (net of taxes of $2 and $4, respectively) (1)

(4

)

 

10

 

 

6

 

Amortization of net actuarial loss (net of taxes of $2 and $1, respectively) (1)

3

 

 

(4

)

 

(1

)

Regulatory account transfer (net of taxes of $1 and $3, respectively) (1)

2

 

 

(6

)

 

(4

)

Net current period other comprehensive loss

4

 

 

 

 

4

 

Ending balance

$

(21

)

 

$

17

 

 

$

(4

)

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

 

The changes, net of income tax, in PG&E Corporation’s accumulated other comprehensive income (loss) for the year ended December 31, 2017 consisted of the following:

(in millions, net of income tax)

Pension

Benefits

 

Other

Benefits

 

Total

Beginning balance

$

(25

)

 

$

16

 

 

$

(9

)

Other comprehensive income before reclassifications:

 

 

 

 

 

Unrecognized prior service cost (net of taxes of $4 and $0, respectively)

(6

)

 

 

 

(6

)

Unrecognized net actuarial loss (net of taxes of $229 and $97, respectively)

333

 

 

141

 

 

474

 

Regulatory account transfer (net of taxes of $225 and $97, respectively)

(327

)

 

(141

)

 

(468

)

Amounts reclassified from other comprehensive income:

 

 

 

 

 

Amortization of prior service cost (net of taxes of $3 and $6, respectively) (1)

(4

)

 

9

 

 

5

 

Amortization of net actuarial loss (net of taxes of $9 and $2, respectively) (1)

13

 

 

2

 

 

15

 

Regulatory account transfer (net of taxes of $6 and $8, respectively) (1)

(9

)

 

(10

)

 

(19

)

Net current period other comprehensive loss

 

 

1

 

 

1

 

Ending balance

$

(25

)

 

$

17

 

 

$

(8

)

 

 

 

 

 

 

(1) These components are included in the computation of net periodic pension and other postretirement benefit costs.  (See Note 11 below for additional details.)

 

Recently Adopted Accounting Standards

 

Revenue Recognition Standard

 

In May 2014, the FASB issued ASU No. 2014-9, Revenue from Contracts with Customers (Topic 606), which amends the previous revenue recognition guidance.  The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability across entities, industries, jurisdictions, and capital markets and to provide more useful information to users of financial statements through improved and expanded disclosure requirements.  PG&E Corporation and the Utility applied the requirements using the modified retrospective method when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018. A majority of the Utility’s revenue from contracts with customers continues to be recognized on a monthly basis based on applicable tariffs and customers' monthly consumption. Such revenue is recognized using the invoice practical expedient which allows an entity to recognize revenue in the amount that directly corresponds to the value transferred to the customer. See "Revenue Recognition" above.

 

Restricted Cash

 

In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows – Restricted Cash (Topic 230), which amends the existing guidance relating to the disclosure of restricted cash and restricted cash equivalents on the statement of cash flows. Amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning and end of period total amounts shown on the statement of cash flows.  Previously, changes in restricted cash were reported within cash flows from investing activities. PG&E Corporation and the Utility applied the requirements on a retrospective basis when the ASU became effective on January 1, 2018. The adoption of this guidance did not have a material impact on the Consolidated Financial Statements as of the adoption date or for the year ended December 31, 2018.

 

The retrospective adjustments to the Consolidated Statements of Cash Flows for PG&E Corporation and the Utility resulted in an increase to Net cash used in investing activities of $227 million, an increase to Cash, cash equivalents and restricted cash at January 1 by $234 million, and an increase to Cash, cash equivalents and restricted cash at December 31 by $7 million for the year ended December 31, 2016.

 

Presentation of Net Periodic Pension and Post-Retirement Benefit Costs

 

In March 2017, the FASB issued ASU No. 2017-07, Compensation – Retirement Benefits (Topic 715), which amends the guidance relating to the presentation of net periodic pension cost and net periodic other post-retirement benefit costs.  PG&E Corporation and the Utility applied the requirements when the ASU became effective on January 1, 2018.

 

On a retrospective basis, the amendment requires an employer to separate the service cost component from the other components of net benefit cost and provides explicit guidance on how to present the service cost component and other components in the income statement.  As a result, the Consolidated Statements of Income for PG&E Corporation and the Utility were restated. This change resulted in increases to Operating and maintenance expenses and Other income, net, of $51 million and $54 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2017 and $97 million and $100 million for PG&E Corporation and the Utility, respectively, for the year ended December 31, 2016.

 

On a prospective basis, the ASU limits the component of net benefit cost eligible to be capitalized to service costs. The FERC has allowed and the Utility has made a one-time election to adopt the new FASB guidance for regulatory filing purposes.  In January 2018, the CPUC approved modifications to the Utility’s calculation for pension-related revenue requirements to allow for capitalization of only the service cost component determined by a plan’s actuary. The capitalization of service costs only results in higher rate base and a reduction in the Utility’s 2018 revenues.  The changes in capitalization of retirement benefits did not have a material impact on PG&E Corporation’s and the Utility’s Consolidated Financial Statements.

 

Recognition and Measurement of Financial Assets and Financial Liabilities

 

In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, which amends the guidance relating to the recognition, measurement, presentation, and disclosure of financial instruments.  The amendments require equity investments (excluding those accounted for under the equity method or those that result in consolidation) to be measured at fair value, with changes in fair value recognized in net income.  The majority of PG&E Corporation’s and the Utility’s investments are held in the nuclear decommissioning trusts and gains or losses are refundable or recoverable, respectively, from customers through rates, therefore gains and losses are deferred and recognized as regulatory assets or liabilities.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2018 and did not have a material impact on the Consolidated Financial Statements and related disclosures.

 

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

 

In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. The amendments in this update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Act. When amounts are reclassified from accumulated other comprehensive income to the Consolidated Statement of Income, PG&E Corporation and the Utility recognize the related income tax expense at the tax rate in effect at that time. The ASU is effective for PG&E Corporation and the Utility on January 1, 2019, and early adoption is permitted. PG&E Corporation and the Utility early adopted this ASU on January 1, 2018, resulting in an immaterial reclassification.

 

Accounting Standards Issued But Not Yet Adopted

 

Recognition of Lease Assets and Liabilities

 

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which amends the guidance relating to the definition of a lease, recognition of ROU assets and lease liabilities on the balance sheet, and the disclosure of key information about leasing arrangements.  Under the new standard, all lessees must recognize an ROU asset and lease liability on the balance sheet. Operating leases were previously not recognized on the balance sheet.  The ASU became effective for PG&E Corporation and the Utility on January 1, 2019.

 

PG&E Corporation and the Utility elected certain practical expedients and will carry forward historical conclusions related to (1) contracts that contain leases, (2) existing lease and easement classification, and (3) initial direct costs. Additionally, PG&E Corporation and the Utility do not intend to restate comparative periods upon adoption.

 

PG&E Corporation and the Utility plan to adopt this guidance in the first quarter of 2019. PG&E Corporation and the Utility will apply the requirements using the modified retrospective method. PG&E Corporation and the Utility expect this standard to increase ROU assets and liabilities by approximately $2.5 billion to $3.0 billion on the Consolidated Balance Sheets and will result in additional footnote disclosures, but do not expect the guidance will have a material impact on the Consolidated Statements of Income and Statements of Cash Flows. The majority of PG&E Corporation and the Utility's leases are power purchase agreements.

 

Fair Value Measurement

 

In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurements, which amends the existing guidance relating to the disclosure requirements for fair value measurements. The ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

 

Intangibles-Goodwill and Other

 

In August 2018, the FASB issued ASU No. 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer's Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract. This ASU will be effective for PG&E Corporation and the Utility on January 1, 2020 with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

 


NOTE 3: REGULATORY ASSETS, LIABILITIES, AND BALANCING ACCOUNTS

 

Regulatory Assets

 

Long-term regulatory assets are comprised of the following:

 

Balance at December 31,

 

Recovery

Period

(in millions)

2018

 

2017

 

 

Pension benefits (1)

$

1,947

 

 

$

1,954

 

 

Indefinitely

Environmental compliance costs

1,013

 

 

837

 

 

32 years

Utility retained generation (2)

274

 

 

319

 

 

8 years

Price risk management

90

 

 

65

 

 

10 years

Unamortized loss, net of gain, on reacquired debt

76

 

 

79

 

 

25 years

Catastrophic event memorandum account (3)

790

 

 

274

 

 

TBD years

Wildfire expense memorandum account (4)

94

 

 

 

 

TBD years

Fire hazard prevention memorandum account (5)

263

 

 

1

 

 

TBD years

Other

417

 

 

264

 

 

Various

Total long-term regulatory assets

$

4,964

 

 

$

3,793

 

 

 

 

 

 

 

 

 

(1) Payments into the pension and other benefits plans are based on annual contribution requirements. As these annual requirements continue indefinitely into the future, the Utility expects to continuously recover pension benefits.

(2) In connection with the settlement agreement entered into among PG&E Corporation, the Utility, and the CPUC in 2003 to resolve the Utility’s 2001 proceeding under Chapter 11, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility’s retained generation assets.  The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities, consistent with the period over which the related revenues are recognized.

(3) Includes costs of responding to catastrophic events that have been declared a disaster or state of emergency by competent federal or state authorities. Recovery of CEMA costs are subject to CPUC review and approval.

(4) Includes specific incremental wildfire liability costs the CPUC approved for tracking in June 2018. Recovery of WEMA costs are subject to CPUC review and approval.

(5) Includes costs associated with the implementation of regulations and requirements adopted to protect the public from potential fire hazards associated with overhead power line facilities and nearby aerial communication facilities that have not been previously authorized in another proceeding. Recovery of FHPMA costs are subject to CPUC review and approval.

 

In general, regulatory assets represent the cumulative differences between amounts recognized for ratemaking purposes and expense or accumulated other comprehensive income (loss) recognized in accordance with GAAP. Additionally, the Utility does not earn a return on regulatory assets if the related costs do not accrue interest.  Accordingly, the Utility earns a return on its regulatory assets for retained generation, and regulatory assets for unamortized loss, net of gain, on reacquired debt.

 

Regulatory Liabilities

 

Long-term regulatory liabilities are comprised of the following:

 

Balance at December 31,

(in millions)

2018

 

2017

Cost of removal obligations (1)

$

5,981

 

 

$

5,547

 

Deferred income taxes (2)

283

 

 

1,021

 

Recoveries in excess of AROs (3)

356

 

 

624

 

Public purpose programs (4)

674

 

 

590

 

Retirement Plan (5)

421

 

 

418

 

Other

824

 

 

479

 

Total long-term regulatory liabilities

$

8,539

 

 

$

8,679

 

 

 

 

 

(1) Represents the cumulative differences between asset removal costs recorded and amounts collected in rates for expected asset removal costs.

(2) Represents the net of amounts owed to customers for deferred taxes collected at higher rates before the Tax Act and amounts owed to the Utility for reversal of deferred taxes subject to flow-through treatment. (See Note 8 below.)

(3) Represents the cumulative differences between ARO expenses and amounts collected in rates.  Decommissioning costs related to the Utility’s nuclear facilities are recovered through rates and are placed in nuclear decommissioning trusts.  This regulatory liability also represents the deferral of realized and unrealized gains and losses on these nuclear decommissioning trust investments.  (See Note 10 below.)

(4) Represents amounts received from customers designated for public purpose program costs expected to be incurred beyond the next 12 months, primarily related to energy efficiency programs.

(5) Represents cumulative differences between incurred costs and amounts collected in rates for Post-Retirement Medical, Post-Retirement Life and Long Term Disability Plans.

 

Regulatory Balancing Accounts

 

The Utility tracks (1) differences between the Utility’s authorized revenue requirement and customer billings, and (2) differences between incurred costs and customer billings.  To the extent these differences are probable of recovery or refund over the next 12 months, the Utility records a current regulatory balancing account receivable or payable.  Regulatory balancing accounts that the Utility expects to collect or refund over a period exceeding 12 months are recorded as other noncurrent assets – regulatory assets or noncurrent liabilities – regulatory liabilities, respectively, in the Consolidated Balance Sheets.  These differences do not have an impact on net income.  Balancing accounts will fluctuate during the year based on seasonal electric and gas usage and the timing of when costs are incurred and customer revenues are collected.

 

Current regulatory balancing accounts receivable and payable are comprised of the following:

 

Receivable

Balance at December 31,

(in millions)

2018

 

2017

Electric distribution

$

160

 

 

$

 

Electric transmission

128

 

 

139

 

Utility generation

79

 

 

 

Gas distribution and transmission

462

 

 

486

 

Energy procurement

168

 

 

71

 

Public purpose programs

111

 

 

103

 

Other

327

 

 

423

 

Total regulatory balancing accounts receivable

$

1,435

 

 

$

1,222

 

 

 

 

Payable

Balance at December 31,

(in millions)

2018

 

2017

Electric distribution

$

 

 

$

72

 

Electric transmission

134

 

 

120

 

Utility generation

 

 

14

 

Gas distribution and transmission

9

 

 

 

Energy procurement

59

 

 

149

 

Public purpose programs

587

 

 

452

 

Other

287

 

 

313

 

Total regulatory balancing accounts payable

$

1,076

 

 

$

1,120

 

 

The electric distribution and utility generation accounts track the collection of revenue requirements approved in the GRC. The electric transmission accounts track recovery of costs related to the transmission of electricity approved in the FERC TO rate cases. The gas distribution and transmission accounts track the collection of revenue requirements approved in the GRC and the GT&S rate case.  Energy procurement balancing accounts track recovery of costs related to the procurement of electricity, including any environmental compliance-related activities.  Public purpose programs balancing accounts are primarily used to record and recover authorized revenue requirements for commission-mandated programs such as energy efficiency.

 

NOTE 4: DEBT

 

Debtor In Possession ("DIP") Facilities

 

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into a Senior Secured Superpriority Debtor in Possession Credit, Guaranty and Security Agreement, dated as of February 1, 2019 (the “DIP Credit Agreement”), among the Utility, as borrower, PG&E Corporation, as guarantor, JPMorgan Chase Bank, N.A., as administrative agent, Citibank, N.A., as collateral agent, and the lenders and issuing banks party thereto (together with such other financial institutions from time to time party thereto, the "DIP Lenders"). The DIP Credit Agreement provides for $5.5 billion in senior secured superpriority debtor in possession credit facilities in the form of (i) a revolving credit facility in an aggregate amount of $3.5 billion (the “DIP Revolving Facility”), including a $1.5 billion letter of credit subfacility, (ii) a term loan facility in an aggregate principal amount of $1.5 billion (the “DIP Initial Term Loan Facility”) and (iii) a delayed draw term loan facility in an aggregate principal amount of $500 million (the “DIP Delayed Draw Term Loan Facility”, together with the DIP Revolving Facility and the DIP Initial Term Loan Facility, the “DIP Facilities”), subject to the terms and conditions set forth therein.

 

On the Petition Date, PG&E Corporation and the Utility filed a motion seeking, among other things, interim and final approval of the DIP Facilities, which motion was granted on an interim basis by the Bankruptcy Court following a hearing on January 31, 2019. As a result of the Bankruptcy Court’s interim approval of the DIP Facilities and the satisfaction of the other conditions thereof, the DIP Credit Agreement became effective on February 1, 2019 and a portion of the DIP Revolving Facility in the amount of $1.5 billion (including $750 million of the letter of credit subfacility) was made available to PG&E Corporation and the Utility. As of February 28, 2019, the remainder of the DIP Revolving Facility (including the remainder of the $1.5 billion letter of credit subfacility), the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility are unavailable for borrowing and will remain unavailable until and unless the Bankruptcy Court approves the availability thereof following a final hearing. PG&E Corporation and the Utility are unable to predict the date of the final hearing, but it is currently scheduled for March 13, 2019. There can be no assurances that the Bankruptcy Court will grant final approval of the DIP Facilities at the final hearing, or at all.

 

Borrowings under the DIP Facilities are senior secured obligations of the Utility, secured by substantially all of the Utility’s assets and entitled to superpriority administrative expense claim status in the Utility’s Chapter 11 Case. The Utility’s obligations under the DIP Facilities are guaranteed by PG&E Corporation, and such guarantee is a senior secured obligation of PG&E Corporation, secured by substantially all of PG&E Corporation’s assets and entitled to superpriority administrative expense claim status in PG&E Corporation’s Chapter 11 Case.

 

The DIP Facilities mature on December 31, 2020, subject to the Utility’s option to extend the maturity to December 31, 2021 if certain terms and conditions are satisfied, including the payment of an extension fee equal to 0.25% of the then-outstanding loans and available commitments. Borrowings under the DIP Facilities will bear interest based, at the Utility’s election, on (1) LIBOR plus an applicable margin or (2) ABR plus an applicable margin. ABR will equal the highest of the following: (i) the administrative agent’s announced base rate, (ii) 0.50% above the (x) federal funds effective rate or (y) the overnight federal funds rate, whichever is higher, (iii) one-month LIBOR plus 1.00% and (iv) zero. With respect to the DIP Revolving Facility, the DIP Initial Term Loan Facility and the DIP Delayed Draw Term Loan Facility, the applicable margin is 2.25% for LIBOR loans and 1.25% for ABR loans.

 

The Utility is also required to pay unused fees of (i) 0.375% per annum in respect of the average daily unutilized commitments under the DIP Revolving Facility and (ii) 1.125% per annum, which amount shall increase to 2.25% per annum after six months, in respect of the average daily unutilized commitments under the DIP Delayed Draw Term Loan Facility. The Utility must also pay (x) a fee equal to the applicable margin with respect to LIBOR loans under the DIP Revolving Facility on the aggregate drawable amount of all outstanding letters of credit under the DIP Revolving Facility and (y) a fronting fee to the relevant issuing DIP Lender equal to 0.125% per annum of the aggregate drawable amount of outstanding letters of credit issued by such issuing DIP Lender.

 

The DIP Credit Agreement includes usual and customary covenants for debtor in possession loan agreements of this type, including covenants limiting PG&E Corporation’s and the Utility’s ability to, among other things, incur additional indebtedness, create liens on assets, make investments, loans or advances, engage in mergers, consolidations, sales of assets and acquisitions, pay dividends and distributions and make payments in respect of junior or pre-petition indebtedness, in each case subject to customary exceptions for debtor in possession loan agreements of this type.

 

The DIP Credit Agreement also includes customary and usual representations and warranties and affirmative covenants, including an obligation to deliver 13-week cash flow forecasts and reports showing variances from such forecasts, in each case on a rolling 4-week basis. PG&E Corporation’s and the Utility’s obligations under the DIP Credit Agreement may be accelerated following certain events of default, including payment defaults, breaches of representations and warranties, covenant defaults, cross-defaults to post-petition or unstayed indebtedness of PG&E Corporation and the Utility and their subsidiaries in excess of $200 million, certain events under ERISA, unstayed judgments in respect of post-petition obligations involving an aggregate liability in excess of $200 million, change of control, specified governmental actions having a material adverse effect or condemnation or damage to a material portion of the collateral. Certain bankruptcy-related events are also events of default, including, but not limited to, the dismissal by the Bankruptcy Court of any of the Chapter 11 Cases, the conversion of any of the Chapter 11 Cases to a case under chapter 7 of the Bankruptcy Code, the appointment of a trustee pursuant to Chapter 11, any order authorizing the DIP Facilities being stayed, vacated, reversed or amended in a manner adverse to the DIP Lenders, the final order approving the DIP Facilities failing to have been entered by April 15, 2019, and certain other events related to the impairment of the DIP Lenders’ rights or liens granted under the DIP Credit Agreement.

 

The proceeds of the borrowings under the DIP Facilities will be used for working capital and general corporate purposes and to pay fees, costs and expenses incurred in connection with the transactions contemplated by the DIP Credit Agreement and professional and other fees and costs of administration incurred in connection with the Chapter 11 Cases.

 

 

Long-Term Debt

 

Debt Obligations Previously Classified as Long Term

 

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt:

 

 

December 31,

(in millions)

 

2018

 

2017

PG&E Corporation

 

 

 

 

Term Loan:

 

 

 

 

Stated Maturity

Interest Rates

 

 

 

2020

variable rate (2)

350

 

 

350

 

Less: Current Portion (1)

 

(350

)

 

 

Total PG&E Corporation long-term debt

 

 

 

350

 

Utility

 

 

 

 

Senior notes:

 

 

 

 

Stated Maturity

Interest Rates

 

 

 

2018

8.25%

 

 

400

 

2020

3.50%

800

 

 

800

 

2021

3.25% to 4.25%

550

 

 

550

 

2022

2.45%

400

 

 

400

 

2023 through 2046

2.95% to 6.35%

15,775

 

 

14,975

 

Unamortized discount, net of premium and debt issuance costs

 

(178

)

 

(185

)

Less: current portion (1)

 

(17,347

)

 

(400

)

Total senior notes, net of current portion

 

 

 

16,540

 

Pollution control bonds:

 

 

 

 

Stated Maturity

Interest Rates

 

 

 

Series 2008 G, due 2018

1.05%

 

 

45

 

Series 2008 F and 2010 E, due 2026 (3)

1.75%

100

 

 

100

 

Series 2009 A-B, due 2026 (4)

variable rate (5)

149

 

 

149

 

Series 1996 C, E, F, 1997 B due 2026 (4)

variable rate (6)

614

 

 

614

 

Less: current portion (1)

 

(863

)

 

(45

)

Total pollution control bonds

 

 

 

863

 

Total Utility long-term debt, net of current portion

 

 

 

17,403

 

Total consolidated long-term debt, net of current portion

 

$

 

 

$

17,753

 

 

 

 

 

 

(1) On January 29, 2019, PG&E Corporation and the Utility commenced reorganization under Chapter 11 of the U.S. Bankruptcy Code. The commencement of the Chapter 11 Cases constituted an event of default or termination event under the above-referenced debt of PG&E Corporation and the Utility. With the exception of Pollution Control Bonds series 2008F and 2010E, where a trustee notice is required to trigger acceleration, the commencement of the Chapter 11 Cases caused an automatic and immediate acceleration of such debt, and the possibility of cure is uncertain. Therefore, all long-term debt is classified as current as of December 31, 2018.

(2) At December 31, 2018, the interest rate on the Term Loan was 3.66%.

(3) Pollution Control Bonds series 2008F and 2010E were remarketed and issued in June 2017.  Although the stated maturity date for both series is 2026, these bonds have a mandatory redemption date of May 31, 2022.

(4) Each series of these bonds is supported by a separate direct-pay letter of credit. Subject to certain requirements, the Utility may choose not to provide a credit facility without issuer consent. Series 2009 A-B bonds have a maturity date of June 5, 2019. In December 2015, Series 1996 C, E, F, 1997 B bonds the letters of credit were extended to December 1, 2020. Although the stated maturity date is 2026, each series will remain outstanding only if the Utility extends or replaces the letter of credit related to the series or otherwise obtains consent from the issuer to the continuation of the series without a credit facility.

(5) At December 31, 2018, the interest rate on these bonds was 2.08%.

(6) At December 31, 2018, the interest rate on these bonds ranged from 2.05% to 2.15%.

 

Pollution Control Bonds

 

The California Pollution Control Financing Authority and the California Infrastructure and Economic Development Bank have issued various series of fixed rate and multi-modal tax-exempt pollution control bonds for the benefit of the Utility.  Substantially all of the net proceeds of the pollution control bonds were used to finance or refinance pollution control and sewage and solid waste disposal facilities at the Geysers geothermal power plant or at the Utility’s Diablo Canyon nuclear power plant.  In 1999, the Utility sold all bond-financed facilities at the non-retired units of the Geysers geothermal power plant to Geysers Power Company, LLC pursuant to purchase and sales agreements stating that Geysers Power Company, LLC will use the bond-financed facilities solely as pollution control facilities for so long as any tax-exempt pollution control bonds issued to finance the Geysers project are outstanding.  Except for components that may have been abandoned in place or disposed of as scrap or that are permanently non-operational, the Utility has no knowledge that Geysers Power Company, LLC intends to cease using the bond-financed facilities solely as pollution control facilities.

 

Repayment Schedule

 

PG&E Corporation's and the Utility's long-term debt is in default, and the Accelerated Direct Financial Obligations became immediately due and payable upon the commencement of the Chapter 11 Cases. PG&E Corporation’s and the Utility’s combined stated long-term debt principal repayment amounts at December 31, 2018 are reflected in the table below:

(in millions,

 

 

 

 

 

 

 

 

 

 

 

 

 

except interest rates)

2019

 

2020

 

2021

 

2022

 

2023

 

Thereafter

 

Total

PG&E Corporation

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable interest rate as of December 31, 2018

%

 

3.51

%

 

%

 

%

 

%

 

%

 

3.51

%

Variable rate obligations

$

 

 

$

350

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

350

 

Utility

 

 

 

 

 

 

 

 

 

 

 

 

 

Average fixed interest rate

%

 

3.50

%

 

3.80

%

 

2.31

%

 

3.83

%

 

4.74

%

 

4.52

%

Fixed rate obligations

$

 

 

$

800

 

 

$

550

 

 

$

500

 

 

$

1,175

 

 

$

14,600

 

 

$

17,625

 

Variable interest rate as of December 31, 2018

1.78

%

 

1.59

%

 

%

 

%

 

%

 

%

 

1.63

%

Variable rate obligations (1)

$

149

 

 

$

614

 

 

$

 

 

$

 

 

$

 

 

$

 

 

$

763

 

Total consolidated debt

$

149

 

 

$

1,764

 

 

$

550

 

 

$

500

 

 

$

1,175

 

 

$

14,600

 

 

$

18,738

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) The bonds due in 2026 are backed by separate letters of credit that expire June 5, 2019, or December 1, 2020.

 

Short-term Borrowings

 

The following table summarizes PG&E Corporation’s and the Utility’s outstanding borrowings and availability under their revolving credit facilities and commercial paper programs at December 31, 2018:

(in millions)

Termination

Date

 

Credit

Facility

Limit

 

 

Borrowings Against Revolver

 

 

Commercial

Paper

Outstanding

 

Facility

Availability

PG&E Corporation

April 2022

 

$

300

 

(1)

 

$

300

 

 

 

$

 

 

$

 

Utility

April 2022

 

$

3,000

 

(2)

 

$

2,965

 

(3)

 

$

 

 

$

35

 

Total revolving credit facilities

 

 

$

3,300

 

 

 

$

3,265

 

 

 

$

 

 

$

35

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Includes a $50 million lender commitment to the letter of credit sublimits and a $100 million commitment for swingline loans defined as loans that are made available on a same-day basis and are repayable in full within 7 days.

(2) Includes a $500 million lender commitment to the letter of credit sublimits and a $75 million commitment for swingline loans.

(3) Includes $80 million of letters of credit.

 

For the year ended December 31, 2018, PG&E Corporation’s average outstanding commercial paper balance was $29 million and the maximum outstanding balance during the year was $137 million.  For the year ended December 31, 2018, the Utility’s average outstanding commercial paper balance was $9 million and the maximum outstanding balance during the year was $205 million.  As of December 31, 2018, PG&E Corporation and the Utility each had no commercial paper borrowings outstanding. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

 

The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of the Accelerated Direct Financial Obligations. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation's term loan facility, as well as short-term borrowings under PG&E Corporation's and the Utility's revolving credit facilities and the Utility's term loan facility. See Note 15 below for more information.

 

Revolving Credit Facilities

 

In May 2017, PG&E Corporation and the Utility each extended the termination dates of their existing revolving credit facilities by one year from April 27, 2021 to April 27, 2022.  As previously disclosed, PG&E Corporation's and the Utility's revolving credit facilities have been subject to an automatic and immediate acceleration as a result of the Chapter 11 Cases. Prior to the Chapter 11 Cases, proceeds from the revolving credit facilities were used for working capital, the repayment of commercial paper, and other corporate purposes.

 

Borrowings under each credit agreement (other than swingline loans) previously bore interest based on the borrower’s credit rating and on each borrower’s election of either (1) LIBOR plus an applicable margin or (2) the base rate plus an applicable margin.  The base rate equaled the higher of the following: the administrative agent’s announced base rate, 0.5% above the overnight federal funds rate, and the one-month LIBOR plus an applicable margin.  The borrower’s credit rating at the time of borrowing determined the applicable rate within the following ranges.  The applicable margin for LIBOR loans ranged between 0.9% and 1.475% under PG&E Corporation’s credit agreement and between 0.8% and 1.275% under the Utility’s credit agreement.  The applicable margin for base rate loans ranged between 0% and 0.475% under PG&E Corporation’s credit agreement and between 0% and 0.275% under the Utility’s credit agreement.  In addition, the facility fee under PG&E Corporation’s and the Utility’s credit agreements ranged between 0.1% and 0.275% and between 0.075% and 0.225%, respectively.

 

PG&E Corporation’s and the Utility’s revolving credit facilities include usual and customary provisions for revolving credit facilities of this type, including those regarding events of default and covenants limiting liens to those permitted under their senior note indentures, mergers, sales of all or substantially all of their assets, and other fundamental changes.  In addition, the respective revolving credit facilities required that PG&E Corporation and the Utility maintain a ratio of total consolidated debt to total consolidated capitalization of at most 65% as of the end of each fiscal quarter.  PG&E Corporation’s revolving credit facility agreement also required that PG&E Corporation own, directly or indirectly, at least 80% of the outstanding common stock and at least 70% of the outstanding voting capital stock of the Utility.

 

Commercial Paper Programs

 

The borrowings from PG&E Corporation’s and the Utility’s commercial paper programs were used primarily to fund temporary financing needs.  PG&E Corporation and the Utility could issue commercial paper up to the maximum amounts of $300 million and $2.5 billion, respectively. PG&E Corporation and the Utility treated the amount of outstanding commercial paper as a reduction to the amount available under their respective revolving credit facilities.  The commercial paper had maturities up to 365 days and ranked equally with PG&E Corporation’s and the Utility’s other unsubordinated and unsecured indebtedness.  Commercial paper notes were sold at an interest rate dictated by the market at the time of issuance.  For 2018, the average yield on outstanding PG&E Corporation and Utility commercial paper was 1.85% and 1.91%, respectively.

 

Other Short-term Borrowings

 

In February 2018, the Utility’s $250 million floating rate unsecured term loan, issued in February 2017, matured and was repaid. In February 2018, the Utility entered into a $250 million floating rate unsecured term loan. The proceeds were used for general corporate purposes, including the repayment of a portion of the Utility’s outstanding commercial paper. As a result of the Chapter 11 Cases, repayment of this loan, which was scheduled to mature on February 22, 2019, has been stayed.

 

As of December 31, 2018, PG&E Corporation and the Utility each had no commercial paper borrowings. PG&E Corporation and the Utility do not expect to be able to access the commercial paper market for the duration of the Chapter 11 Cases.

 

In November 2018, the Utility's $500 million floating rate unsecured term loan, issued in November 2017, matured and was repaid.

 

NOTE 5: COMMON STOCK AND SHARE-BASED COMPENSATION

 

PG&E Corporation had 520,338,710 shares of common stock outstanding at December 31, 2018.  PG&E Corporation held all of the Utility’s outstanding common stock at December 31, 2018.

 

During 2018, PG&E Corporation sold no shares of common stock under the February 2017 EDA.

 

In addition, during 2018, PG&E Corporation sold 5.6 million shares of common stock under its 401(k) plan, the Dividend Reinvestment and Stock Purchase Plan, and share-based compensation plans for total cash proceeds of $199 million. Beginning January 1, 2019 PG&E Corporation changed its default matching contributions under its 401(k) plan from PG&E common stock to cash.

 

Dividends

 

On December 20, 2017, the Boards of Directors of PG&E Corporation and the Utility suspended quarterly cash dividends on both PG&E Corporation’s and the Utility’s common stock, beginning the fourth quarter of 2017, as well as the Utility’s preferred stock, beginning the three-month period ending January 31, 2018, due to the uncertainty related to the causes of and potential liabilities associated with wildfires. See Wildfire-related contingencies in Note 13 below.

 

Under the Utility’s Articles of Incorporation, the Utility cannot pay common stock dividends unless all cumulative preferred dividends on the Utility’s preferred stock have been paid.  Under their respective credit agreements, PG&E Corporation and the Utility are each required to maintain a ratio of consolidated total debt to consolidated capitalization of at most 65%.  Based on the calculation of this ratio for each company, no amount of PG&E Corporation's retained earnings and $1.4 billion of the Utility's retained earnings was subject to this restriction at December 31, 2018.  Additionally, the Utility's net assets, and therefore its ability to pay dividends, are restricted by the CPUC-authorized capital structure, which requires the Utility to maintain, on average, at least 52% equity.  Based on the calculation of this ratio, none of the Utility's net assets were restricted at December 31, 2018.  Additionally, as a result of this requirement, the Utility's ability to pay dividends in the future could be impacted by future potential liabilities.  PG&E Corporation does not expect to pay any cash dividends for the foreseeable future.

 

Long-Term Incentive Plan

 

The PG&E Corporation LTIP permits various forms of share-based incentive awards, including stock options, restricted stock units, performance shares, and other share-based awards, to eligible employees of PG&E Corporation and its subsidiaries.  Non-employee directors of PG&E Corporation are also eligible to receive certain share-based awards.  A maximum of 17 million shares of PG&E Corporation common stock (subject to certain adjustments) has been reserved for issuance under the 2014 LTIP, of which 15,150,532 shares were available for future awards at December 31, 2018.

 

The following table provides a summary of total share-based compensation expense recognized by PG&E Corporation for share-based incentive awards for 2018:

(in millions)

2018

 

2017

 

2016

Stock Options

$

10

 

 

$

 

 

$

 

Restricted stock units

43

 

 

40

 

 

53

 

Performance shares

36

 

 

45

 

 

55

 

Total compensation expense (pre-tax)

$

89

 

 

$

85

 

 

$

108

 

Total compensation expense (after-tax)

$

63

 

 

$

50

 

 

$

64

 

 

Share-based compensation costs are generally not capitalized.  There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

 

Stock Options

 

The exercise price of stock options granted under the 2014 LTIP and all other outstanding stock options is equal to the market price of PG&E Corporation’s common stock on the date of grant.  Stock options generally have a 10-year term and vest over four years of continuous service, subject to accelerated vesting in certain circumstances. As of December 31, 2018, $1.5 million of total unrecognized compensation costs related to nonvested stock options were expected to be recognized over a weighted average period of a year and a half for PG&E Corporation.

 

The fair value of each stock option on the date of grant is estimated using the Black-Scholes valuation method.  The weighted average grant date fair value of options granted using the Black-Scholes valuation method was $10.24 per share in 2018.  The significant assumptions used for shares granted in 2018 were:

 

2018

Expected stock price volatility

23.00

%

Expected annual dividend payment

3.10

%

Risk-free interest rate

2.58

%

Expected life (years)

6

 

Expected volatilities are based on historical volatility of PG&E Corporation’s common stock.  The expected dividend payment is the dividend yield at the date of grant.  The risk-free interest rate for periods within the contractual term of the stock option is based on the U.S. Treasury rates in effect at the date of grant.  The expected life of stock options is derived from historical data that estimates stock option exercises and employee departure behavior.

 

There was no tax benefit recognized from stock options for the year ended December 31, 2018.

 

The following table summarizes stock option activity for PG&E Corporation and the Utility for 2018:

 

Number of
Stock Option

 

Weighted Average Grant-
Date Fair Value

 

Weighted Average Remaining Contractual Term

 

Aggregate Intrinsic Value

Outstanding at January 1

 

 

N/A

 

N/A

 

N/A

Granted

1,571,876

 

 

$

10.24

 

 

 

 

 

Vested

 

 

N/A

 

 

 

 

Forfeited

(49,739

)

 

10.23

 

 

 

 

Outstanding at December 31

1,522,137

 

 

10.24

 

9.17

 

0

Expected to vest at December 31

1,430,407

 

 

$

10.24

 

 

9.17

 

0

Exercisable at December 31

 

 

N/A

 

N/A

 

N/A

 

 

 

 

 

 

 

 

 

Restricted Stock Units

 

Restricted stock units granted after 2014 generally vest equally over three years. Vested restricted stock units are settled in shares of PG&E Corporation common stock accompanied by cash payments to settle any dividend equivalents associated with the vested restricted stock units.  Compensation expense is generally recognized ratably over the vesting period based on grant-date fair value.  The weighted average grant-date fair value for restricted stock units granted during 2018, 2017, and 2016 was $40.92, $66.95, and $56.68, respectively.  The total fair value of restricted stock units that vested during 2018, 2017, and 2016 was $41 million, $57 million, and $36 million, respectively.  The tax benefit from restricted stock units that vested during each period was not material.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2018, $43 million of total unrecognized compensation costs related to nonvested restricted stock units was expected to be recognized over the remaining weighted average period of 1.79 years.

 

The following table summarizes restricted stock unit activity for 2018:

 

Number of

Restricted Stock Units

 

Weighted Average Grant-

Date Fair Value

Nonvested at January 1

1,379,235

 

 

$

60.93

 

Granted

1,415,627

 

 

40.92

 

Vested

(691,408

)

 

58.78

 

Forfeited

(123,642

)

 

56.38

 

Nonvested at December 31

1,979,812

 

 

$

47.66

 

 

Performance Shares

 

Performance shares generally will vest three years after the grant date.  Upon vesting, performance shares are settled in shares of common stock based on either PG&E Corporation’s total shareholder return relative to a specified group of industry peer companies over a three-year performance period or, for a small number of awards, an internal PG&E Corporation metric.  Dividend equivalents are paid in cash based on the amount of common stock to which the recipients are entitled.

 

Compensation expense attributable to performance share is generally recognized ratably over the applicable three-year period based on the grant-date fair value determined using a Monte Carlo simulation valuation model for the total shareholder return based awards or the grant-date market value of PG&E Corporation common stock for internal metric based awards.  The weighted average grant-date fair value for performance shares granted during 2018, 2017, and 2016 was $36.92, $77.00, and $53.61 respectively.  There was no tax benefit associated with performance shares during each of these periods.  In general, forfeitures are recorded ratably over the vesting period, using historical averages and adjusted to actuals when vesting occurs.  As of December 31, 2018, $31 million of total unrecognized compensation costs related to nonvested performance shares was expected to be recognized over the remaining weighted average period of 1.68 years.

 

The following table summarizes activity for performance shares in 2018:

 

Number of

Performance Shares

 

Weighted Average Grant-

Date Fair Value

Nonvested at January 1

1,748,028

 

 

$

63.40

 

Granted

763,392

 

 

36.92

 

Vested

(156,747

)

 

56.24

 

Forfeited (1)

(916,582

)

 

53.68

 

Nonvested at December 31

1,438,091

 

 

$

56.32

 

 

 

 

 

(1) Includes performance shares that expired with zero value as performance targets were not met.

 

NOTE 6: PREFERRED STOCK

 

PG&E Corporation has authorized 80 million shares of no par value preferred stock and 5 million shares of $100 par value preferred stock, which may be issued as redeemable or nonredeemable preferred stock.  PG&E Corporation does not have any preferred stock outstanding.

 

The Utility has authorized 75 million shares of $25 par value preferred stock and 10 million shares of $100 par value preferred stock.  At December 31, 2018 and December 31, 2017, the Utility’s preferred stock outstanding included $145 million of shares with interest rates between 5% and 6% designated as nonredeemable preferred stock and $113 million of shares with interest rates between 4.36% and 5% that are redeemable between $25.75 and $27.25 per share.  The Utility’s preferred stock outstanding are not subject to mandatory redemption.  All outstanding preferred stock has a $25 par value.

 

At December 31, 2018, annual dividends on the Utility’s nonredeemable preferred stock ranged from $1.25 to $1.50 per share.  The Utility’s redeemable preferred stock is subject to redemption at the Utility’s option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date.  At December 31, 2018, annual dividends on redeemable preferred stock ranged from $1.09 to $1.25 per share.

 

Dividends on all Utility preferred stock are cumulative.  All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights.  Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.  The Utility paid no dividends on preferred stock in 2018 (See "Dividends" in Note 5, above). The Utility paid $14 million of dividends on preferred stock in 2017 and 2016.

 

NOTE 7: EARNINGS PER SHARE

 

PG&E Corporation’s basic EPS is calculated by dividing the income available for common shareholders by the weighted average number of common shares outstanding.  PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding share-based compensation in the calculation of diluted EPS.  The following is a reconciliation of PG&E Corporation’s income available for common shareholders and weighted average common shares outstanding for calculating diluted EPS for 2018, 2017, and 2016.

 

Year Ended December 31,

(in millions, except per share amounts)

2018

 

2017

 

2016

Income available for common shareholders

$

(6,851

)

 

$

1,646

 

 

$

1,393

 

Weighted average common shares outstanding, basic

517

 

 

512

 

 

499

 

Add incremental shares from assumed conversions:

 

 

 

 

 

Employee share-based compensation

 

 

1

 

 

2

 

Weighted average common share outstanding, diluted

517

 

 

513

 

 

501

 

Total earnings per common share, diluted

$

(13.25

)

 

$

3.21

 

 

$

2.78

 

 

For each of the periods presented above, the calculation of outstanding common shares on a diluted basis excluded an insignificant amount of options and securities that were antidilutive.

 

NOTE 8: INCOME TAXES

 

PG&E Corporation and the Utility use the asset and liability method of accounting for income taxes.  The income tax provision includes current and deferred income taxes resulting from operations during the year. PG&E Corporation and the Utility estimate current period tax expense in addition to calculating deferred tax assets and liabilities.  Deferred tax assets and liabilities result from temporary tax and accounting timing differences, such as those arising from depreciation expense.

 

PG&E Corporation and the Utility recognize a tax benefit if it is more likely than not that a tax position taken or expected to be taken in a tax return will be sustained upon examination by taxing authorities based on the merits of the position.  The tax benefit recognized in the financial statements is measured based on the largest amount of benefit that is greater than 50% likely of being realized upon settlement.  As such, the difference between a tax position taken or expected to be taken in a tax return in future periods and the benefit recognized and measured pursuant to this guidance in the financial statements represents an unrecognized tax benefit.

 

Investment tax credits are deferred and amortized to income over time.  PG&E Corporation amortizes its investment tax credits over the projected investment recovery period.  The Utility amortizes its investment tax credits over the life of the related property in accordance with regulatory treatment.

 

PG&E Corporation files a consolidated U.S. federal income tax return that includes the Utility and domestic subsidiaries in which its ownership is 80% or more.  PG&E Corporation files a combined state income tax return in California.  PG&E Corporation and the Utility are parties to a tax-sharing agreement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

 

The significant components of income tax provision (benefit) by taxing jurisdiction were as follows:

 

PG&E Corporation

 

Utility

 

Year Ended December 31,

(in millions)

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Current:

 

 

 

 

 

 

 

 

 

 

 

Federal

$

(5

)

 

$

(10

)

 

$

(105

)

 

$

5

 

 

$

61

 

 

$

(105

)

State

(8

)

 

48

 

 

(70

)

 

(7

)

 

50

 

 

(66

)

Deferred:

 

 

 

 

 

 

 

 

 

 

 

Federal

(2,264

)

 

481

 

 

218

 

 

(2,278

)

 

326

 

 

229

 

State

(1,009

)

 

6

 

 

16

 

 

(1,009

)

 

4

 

 

16

 

Tax credits

(6

)

 

(14

)

 

(4

)

 

(6

)

 

(14

)

 

(4

)

Income tax provision (benefit)

$

(3,292

)

 

$

511

 

 

$

55

 

 

$

(3,295

)

 

$

427

 

 

$

70

 

 

 

The following table describes net deferred income tax liabilities:

 

PG&E Corporation

 

Utility

 

Year Ended December 31,

(in millions)

2018

 

2017

 

2018

 

2017

Deferred income tax assets:

 

 

 

 

 

 

 

Tax carryforwards

$

740

 

 

$

830

 

 

$

650

 

 

$

736

 

Compensation

173

 

 

274

 

 

121

 

 

205

 

Income tax regulatory liability(1)

79

 

 

286

 

 

79

 

 

286

 

Wildfire-related Reserve (2)

3,433

 

 

34

 

 

3,433

 

 

34

 

Other (3)

87

 

 

151

 

 

93

 

 

160

 

Total deferred income tax assets

$

4,512

 

 

$

1,575

 

 

$

4,376

 

 

$

1,421

 

Deferred income tax liabilities:

 

 

 

 

 

 

 

Property related basis differences

7,672

 

 

7,269

 

 

7,660

 

 

7,256

 

Other (4)

121

 

 

128

 

 

121

 

 

128

 

Total deferred income tax liabilities

$

7,793

 

 

$

7,397

 

 

$

7,781

 

 

$

7,384

 

Total net deferred income tax liabilities

$

3,281

 

 

$

5,822

 

 

$

3,405

 

 

$

5,963

 

 

 

 

 

 

 

 

 

(1) Represents the tax gross up portion of the deferred income tax for the cumulative differences between amounts recognized for ratemaking purposes and amounts recognized for tax, including the impact of changes in net deferred taxes associated with a lower federal income tax rate as a result of the Tax Act.  (For more information see Note 3 above).

(2) Amounts primarily relate to wildfire-related claims, net of estimated insurance recoveries, and legal and other costs related to the 2018 Camp fire, 2017 Northern California wildfires, and the 2015 Butte fire.

(3) Amounts include benefits, environmental reserve, and customer advances for construction.

(4) Amounts primarily relate to regulatory balancing accounts.

 

The following table reconciles income tax expense at the federal statutory rate to the income tax provision:

 

PG&E Corporation

 

Utility

 

Year Ended December 31,

 

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Federal statutory income tax rate

21.0

%

 

35.0

%

 

35.0

%

 

21.0

%

 

35.0

%

 

35.0

%

Increase (decrease) in income tax rate resulting from:

 

 

 

 

 

 

 

 

 

 

 

State income tax (net of federal benefit) (1)

7.9

 

 

1.5

 

 

(2.5

)

 

7.9

 

 

1.6

 

 

(2.2

)

Effect of regulatory treatment of fixed asset differences (2)

3.6

 

 

(16.5

)

 

(23.7

)

 

3.6

 

 

(16.8

)

 

(23.4

)

Tax credits

0.1

 

 

(1.1

)

 

(0.8

)

 

0.1

 

 

(1.1

)

 

(0.8

)

Benefit of loss carryback

 

 

 

 

(1.1

)

 

 

 

 

 

(1.1

)

Compensation Related (3)

(0.2

)

 

(1.0

)

 

(0.1

)

 

(0.1

)

 

(0.9

)

 

(0.2

)

Tax Reform Adjustment (4)

0.1

 

 

6.8

 

 

 

 

0.1

 

 

3.0

 

 

 

Other, net (5)

 

 

(1.1

)

 

(3.0

)

 

 

 

(0.7

)

 

(2.5

)

Effective tax rate

32.5

%

 

23.6

%

 

3.8

%

 

32.6

%

 

20.1

%

 

4.8

%

 

 

 

 

 

 

 

 

 

 

 

 

(1) Includes the effect of state flow-through ratemaking treatment.  In 2016, amounts reflect a settlement with the IRS on a 2011 audit related to electric transmission and distribution repairs deductions.

(2) Includes the effect of federal flow-through ratemaking treatment for certain property-related costs as authorized by the 2014 GRC decision (impacting the twelve months ended December 31, 2017), the 2017 GRC decision (impacting the twelve months ended December 31, 2018), and by the 2015 GT&S decision which impacted all periods presented.  All amounts are impacted by the level of income before income taxes.  The 2014 GRC, 2017 GRC, and 2015 GT&S rate case decisions authorized revenue requirements that reflect flow-through ratemaking for temporary income tax differences attributable to repair costs and certain other property-related costs for federal tax purposes.  For these temporary tax differences, PG&E Corporation and the Utility recognize the deferred tax impact in the current period and record offsetting regulatory assets and liabilities.  Therefore, PG&E Corporation’s and the Utility’s effective tax rates are impacted as these differences arise and reverse.  PG&E Corporation and the Utility recognize such differences as regulatory assets or liabilities as it is probable that these amounts will be recovered from or returned to customers in future rates.  In 2018, the amounts also reflect the impact of the amortization of excess deferred tax benefits to be refunded to customers as a result of the Tax Act passed in December 2017.

(3) Primarily represents adjustments to compensation as a result of the enactment of the Tax Act.

(4) Represents adjustments to deferred tax balances under Staff Accounting Bulletin No. 118 reflecting the tax rate reduction required by the Tax Act.

(5) These amounts primarily represents the impact of tax audit settlements.

 

Unrecognized tax benefits

 

The following table reconciles the changes in unrecognized tax benefits:

 

PG&E Corporation

 

Utility

(in millions)

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Balance at beginning of year

$

349

 

 

$

388

 

 

$

468

 

 

$

349

 

 

$

382

 

 

$

462

 

Reductions for tax position taken during a prior year

(27

)

 

(71

)

 

(77

)

 

(27

)

 

(71

)

 

(77

)

Additions for tax position taken during the current year

55

 

 

48

 

 

56

 

 

55

 

 

48

 

 

56

 

Settlements

 

 

(14

)

 

(59

)

 

 

 

(8

)

 

(59

)

Expiration of statute

 

 

(3

)

 

 

 

 

 

(3

)

 

 

Balance at end of year

$

377

 

 

$

349

 

 

$

388

 

 

$

377

 

 

$

349

 

 

$

382

 

 

The component of unrecognized tax benefits that, if recognized, would affect the effective tax rate at December 31, 2018 for PG&E Corporation and the Utility was $5 million.

 

PG&E Corporation’s and the Utility’s unrecognized tax benefits may change significantly within the next 12 months due to the resolution of several matters, including audits.  As of December 31, 2018, it is reasonably possible that unrecognized tax benefits will decrease by approximately $50 million within the next 12 months.

 

Interest income, interest expense and penalties associated with income taxes are reflected in income tax expense on the Consolidated Statements of Income.  For the years ended December 31, 2018, 2017, and 2016, these amounts were immaterial.

 

Tax Cuts and Jobs Act of 2017

 

On December 22, 2017, the U.S. government enacted expansive tax legislation commonly referred to as the Tax Act. Among other provisions, the Tax Act reduces the federal income tax rate from 35% to 21% beginning on January 1, 2018 and eliminated bonus depreciation for utilities. At December 31, 2017, PG&E Corporation and the Utility recorded estimated provisional amounts to reflect the effect of the Tax Act in accordance with Staff Accounting Bulletin No. 118.  In 2018, PG&E Corporation and the Utility recorded an approximately $13 million tax benefit to adjust the amount recorded in 2017 for the Tax Act upon obtaining, preparing, and analyzing additional information regarding facts and circumstances that existed as of the enactment date that, if known, would have affected the income tax effects initially reported as provisional amounts.

 

Although the accounting under ASC 740 to reflect the Tax Act is now complete, the Treasury is still issuing interpretive guidance on various aspects of the Tax Act. If future guidance requires a change in the recorded tax amounts, any necessary change will be reflected in the period such guidance is issued.

 

In addition, the Utility filed the estimated revenue impact of the Tax Act with the CPUC and FERC in March and May of 2018, respectively. As of December 31, 2018, the Utility still has not received final regulatory decisions. Depending on the final regulatory outcome, an adjustment may need to be made in the period the final decisions are issued.

 

Tax settlements

 

PG&E Corporation’s tax returns have been accepted through 2015 except for a few matters, the most significant of which relate to deductible repair costs for gas transmission and distribution lines of business and tax deductions claimed for regulatory fines and fees assessed as part of the Penalty Decision issued in 2015 for the San Bruno natural gas explosion in September of 2010. In February 2017, the Joint Committee of Taxation approved PG&E Corporation’s settlement with the IRS related to deductible electric transmission and distribution repairs for the 2011 and 2012 tax years.  The agreement provided that the methodology used in determining the deductible amount should be followed for all subsequent periods, absent any material change in facts.  In November 2017, PG&E Corporation reached an agreement with the IRS on deductible generation repairs for the 2013 and 2014 tax years.

 

Tax years after 2007 remain subject to examination by the state of California.

 

Carryforwards

 

The following table describes PG&E Corporation’s operating loss and tax credit carryforward balances:

(in millions)

December 31,
2018

 

Expiration

Year

Federal:

 

 

 

Net operating loss carryforward

$

3,880

 

 

2031 - 2036

Tax credit carryforward

118

 

 

2029 - 2037

Charitable contribution loss carryforward

10

 

 

2020

 

 

 

 

State:

 

 

 

Net operating loss carryforward

$

58

 

 

2038

Tax credit carryforward

79

 

 

Various

Charitable contribution loss carryforward

10

 

 

2020 - 2021

 

PG&E Corporation believes it is more likely than not the tax benefits associated with the federal and California net operating losses, charitable contributions and tax credits can be realized within the carryforward periods, therefore no valuation allowance was recognized as of December 31, 2018 for these tax attributes.

 

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation does not believe that the Chapter 11 Cases resulted in loss of or limitation on the utilization of any of the tax carryforwards. PG&E Corporation will continue to monitor the status during the pendency of the Chapter 11 Cases.

 

NOTE 9: DERIVATIVES

 

Use of Derivative Instruments

 

The Utility is exposed to commodity price risk as a result of its electricity and natural gas procurement activities. Procurement costs are recovered through customer rates. The Utility uses both derivative and non-derivative contracts to manage volatility in customer rates due to fluctuating commodity prices. Derivatives include contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

 

Derivatives are presented in the Utility’s Consolidated Balance Sheets recorded at fair value and on a net basis in accordance with master netting arrangements for each counter-party. The fair value of derivative instruments is further offset by cash collateral paid or received where the right of offset and the intention to offset exist.

 

Price risk management instruments are not held for speculative purposes and are subject to certain regulatory requirements.  The Utility expects to fully recover in rates all costs related to derivatives under the applicable ratemaking mechanism in place as long as the Utility’s price risk management activities are carried out in accordance with CPUC directives.  Therefore, all unrealized gains and losses associated with the change in fair value of these derivatives are deferred and recorded within the Utility’s regulatory assets and liabilities on the Consolidated Balance Sheets.  Net realized gains or losses on commodity derivatives are recorded in the cost of electricity or the cost of natural gas with corresponding increases or decreases to regulatory balancing accounts for recovery from or refund to customers.

 

The Utility elects the normal purchase and sale exception for eligible derivatives.  Eligible derivatives are those that require physical delivery in quantities that are expected to be used by the Utility over a reasonable period in the normal course of business, and do not contain pricing provisions unrelated to the commodity delivered.  These items are not reflected in the Consolidated Balance Sheets at fair value.

 

Volume of Derivative Activity

 

At December 31, 2018 and 2017, respectively, the volumes of the Utility’s outstanding derivatives were as follows:

 

 

 

 

Contract Volume

Underlying Product

 

Instruments

 

2018

 

2017

Natural Gas (1) (MMBtus (2))

 

Forwards and Swaps

 

177,750,349

 

 

228,768,745

 

 

 

Options

 

13,735,405

 

 

60,736,806

 

Electricity (Megawatt-hours)

 

Forwards and Swaps

 

3,833,490

 

 

2,872,013

 

 

 

Congestion Revenue Rights (3)

 

340,783,089

 

 

312,272,177

 

 

 

 

 

 

 

 

(1) Amounts shown are for the combined positions of the electric fuels and core gas supply portfolios.

(2) Million British Thermal Units.

(3) CRRs are financial instruments that enable the holders to manage variability in electric energy congestion charges due to transmission grid limitations.

 

Presentation of Derivative Instruments in the Financial Statements

 

At December 31, 2018, the Utility’s outstanding derivative balances were as follows:

 

Commodity Risk

(in millions)

Gross Derivative

Balance

 

Netting

 

Cash Collateral

 

Total Derivative

Balance

Current assets – other

$

44

 

 

$

(1

)

 

$

89

 

 

$

132

 

Other noncurrent assets – other

165

 

 

 

 

 

 

165

 

Current liabilities – other

(29

)

 

1

 

 

7

 

 

(21

)

Noncurrent liabilities – other

(90

)

 

 

 

2

 

 

(88

)

Total commodity risk

$

90

 

 

$

 

 

$

98

 

 

$

188

 

 

 

At December 31, 2017, the Utility’s outstanding derivative balances were as follows:

 

Commodity Risk

(in millions)

Gross Derivative

Balance

 

Netting

 

Cash Collateral

 

Total Derivative

Balance

Current assets – other

$

30

 

 

$

(3

)

 

$

10

 

 

$

37

 

Other noncurrent assets – other

103

 

 

(1

)

 

 

 

102

 

Current liabilities – other

(47

)

 

3

 

 

13

 

 

(31

)

Noncurrent liabilities – other

(66

)

 

1

 

 

8

 

 

(57

)

Total commodity risk

$

20

 

 

$

 

 

$

31

 

 

$

51

 

 

Cash inflows and outflows associated with derivatives are included in operating cash flows on the Utility’s Consolidated Statements of Cash Flows.

 

The majority of the Utility’s derivatives instruments, including certain power purchase agreements, contain collateral posting provisions tied to the Utility’s credit rating from each of the major credit rating agencies, also known as a credit-risk-related contingent feature. In January 2019, multiple credit rating agencies downgraded the Utility below investment grade, resulting in the Utility posting $6.2 million to fully collateralize its net liability derivative positions.

 

NOTE 10: FAIR VALUE MEASUREMENTS

 

PG&E Corporation and the Utility measure their cash equivalents, trust assets and price risk management instruments at fair value.  A three-tier fair value hierarchy is established that prioritizes the inputs to valuation methodologies used to measure fair value:

 

  • Level 1 – Observable inputs that reflect quoted prices (unadjusted) for identical assets or liabilities in active markets.

 

  • Level 2 – Other inputs that are directly or indirectly observable in the marketplace.

 

  • Level 3 – Unobservable inputs which are supported by little or no market activities.

 

The fair value hierarchy requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

 

Assets and liabilities measured at fair value on a recurring basis for PG&E Corporation and the Utility are summarized below.  Assets held in rabbi trusts are held by PG&E Corporation and not the Utility.

 

Fair Value Measurements

 

At December 31, 2018

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

Short-term investments

$

1,593

 

 

$

 

 

$

 

 

$

 

 

$

1,593

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

Short-term investments

29

 

 

 

 

 

 

 

 

29

 

Global equity securities

1,793

 

 

 

 

 

 

 

 

1,793

 

Fixed-income securities

661

 

 

639

 

 

 

 

 

 

1,300

 

Assets measured at NAV

 

 

 

 

 

 

 

 

16

 

Total nuclear decommissioning trusts (2)

2,483

 

 

639

 

 

 

 

 

 

3,138

 

Price risk management instruments (Note 9)

 

 

 

 

 

 

 

 

 

Electricity

 

 

5

 

 

203

 

 

51

 

 

259

 

Gas

 

 

1

 

 

 

 

37

 

 

38

 

Total price risk management instruments

 

 

6

 

 

203

 

 

88

 

 

297

 

Rabbi trusts

 

 

 

 

 

 

 

 

 

Fixed-income securities

 

 

93

 

 

 

 

 

 

93

 

Life insurance contracts

 

 

67

 

 

 

 

 

 

67

 

Total rabbi trusts

 

 

160

 

 

 

 

 

 

160

 

Long-term disability trust

 

 

 

 

 

 

 

 

 

Short-term investments

7

 

 

 

 

 

 

 

 

7

 

Assets measured at NAV

 

 

 

 

 

 

 

 

155

 

Total long-term disability trust

7

 

 

 

 

 

 

 

 

162

 

TOTAL ASSETS

$

4,083

 

 

$

805

 

 

$

203

 

 

$

88

 

 

$

5,350

 

Liabilities:

 

 

 

 

 

 

 

 

 

Price risk management instruments (Note 9)

 

 

 

 

 

 

 

 

 

Electricity

$

4

 

 

$

5

 

 

$

108

 

 

$

(10

)

 

$

107

 

Gas

 

 

2

 

 

 

 

 

 

2

 

TOTAL LIABILITIES

$

4

 

 

$

7

 

 

$

108

 

 

$

(10

)

 

$

109

 

 

 

 

 

 

 

 

 

 

 

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $408 million, primarily related to deferred taxes on appreciation of investment value.

 

 

Fair Value Measurements

 

At December 31, 2017

(in millions)

Level 1

 

Level 2

 

Level 3

 

Netting (1)

 

Total

Assets:

 

 

 

 

 

 

 

 

 

Short-term investments

$

385

 

 

$

 

 

$

 

 

$

 

 

$

385

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

 

 

Short-term investments

23

 

 

 

 

 

 

 

 

23

 

Global equity securities

1,967

 

 

 

 

 

 

 

 

1,967

 

Fixed-income securities

733

 

 

562

 

 

 

 

 

 

1,295

 

Assets measured at NAV

 

 

 

 

 

 

 

 

18

 

Total nuclear decommissioning trusts (2)

2,723

 

 

562

 

 

 

 

 

 

3,303

 

Price risk management instruments (Note 9)

 

 

 

 

 

 

 

 

 

Electricity

 

 

3

 

 

129

 

 

6

 

 

138

 

Gas

 

 

1

 

 

 

 

 

 

1

 

Total price risk management instruments

 

 

4

 

 

129

 

 

6

 

 

139

 

Rabbi trusts

 

 

 

 

 

 

 

 

 

Fixed-income securities

 

 

72

 

 

 

 

 

 

72

 

Life insurance contracts

 

 

71

 

 

 

 

 

 

71

 

Total rabbi trusts

 

 

143

 

 

 

 

 

 

143

 

Long-term disability trust

 

 

 

 

 

 

 

 

 

Short-term investments

8

 

 

 

 

 

 

 

 

8

 

Assets measured at NAV

 

 

 

 

 

 

 

 

167

 

Total long-term disability trust

8

 

 

 

 

 

 

 

 

175

 

TOTAL ASSETS

$

3,116

 

 

$

709

 

 

$

129

 

 

$

6

 

 

$

4,145

 

Liabilities:

 

 

 

 

 

 

 

 

 

Price risk management instruments (Note 9)

 

 

 

 

 

 

 

 

 

Electricity

10

 

 

15

 

 

87

 

 

(25

)

 

87

 

Gas

 

 

1

 

 

 

 

 

 

1

 

TOTAL LIABILITIES

$

10

 

 

$

16

 

 

$

87

 

 

$

(25

)

 

$

88

 

 

 

 

 

 

 

 

 

 

 

(1) Includes the effect of the contractual ability to settle contracts under master netting agreements and margin cash collateral.

(2) Represents amount before deducting $440 million, primarily related to deferred taxes on appreciation of investment value.

 

Valuation Techniques

 

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.  There are no restrictions on the terms and conditions upon which the investments may be redeemed.  Transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  There were no material transfers between any levels for the years ended December 31, 2018 and 2017.

 

Trust Assets

 

Assets Measured at Fair Value

 

In general, investments held in the trusts are exposed to various risks, such as interest rate, credit, and market volatility risks.

Nuclear decommissioning trust assets and other trust assets are composed primarily of equity and fixed-income securities and also include short-term investments that are money market funds valued at Level 1.

 

Global equity securities primarily include investments in common stock that are valued based on quoted prices in active markets and are classified as Level 1.

 

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of fixed-income securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

 

Assets Measured at NAV Using Practical Expedient

 

Investments in the nuclear decommissioning trusts and the long-term disability trust that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above.  The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets.  These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities and asset-backed securities.

 

Price Risk Management Instruments

 

Price risk management instruments include physical and financial derivative contracts, such as power purchase agreements, forwards, futures, swaps, options, and CRRs that are traded either on an exchange or over-the-counter.

 

Power purchase agreements, forwards, and swaps are valued using a discounted cash flow model.  Exchange-traded futures that are valued using observable market forward prices for the underlying commodity are classified as Level 1.  Over-the-counter forwards and swaps that are identical to exchange-traded futures, or are valued using forward prices from broker quotes that are corroborated with market data are classified as Level 2.  Exchange-traded options are valued using observable market data and market-corroborated data and are classified as Level 2.

 

Long-dated power purchase agreements that are valued using significant unobservable data are classified as Level 3.  These Level 3 contracts are valued using either estimated basis adjustments from liquid trading points or techniques, including extrapolation from observable prices, when a contract term extends beyond a period for which market data is available.  Market and credit risk management utilizes models to derive pricing inputs for the valuation of the Utility’s Level 3 instruments using pricing inputs from brokers and historical data.

 

The Utility holds CRRs to hedge the financial risk of CAISO-imposed congestion charges in the day-ahead market.  Limited market data is available in the CAISO auction and between auction dates; therefore, the Utility utilizes historical prices to forecast forward prices. CRRs are classified as Level 3.

 

Level 3 Measurements and Sensitivity Analysis

 

The Utility’s market and credit risk management function, which reports to the Chief Financial Officer, is responsible for determining the fair value of the Utility’s price risk management derivatives.  The Utility’s finance and risk management functions collaborate to determine the appropriate fair value methodologies and classification for each derivative.  Inputs used and the fair value of Level 3 instruments are reviewed period-over-period and compared with market conditions to determine reasonableness.

 

Significant increases or decreases in any of those inputs would result in a significantly higher or lower fair value, respectively.  All reasonable costs related to Level 3 instruments are expected to be recoverable through customer rates; therefore, there is no impact to net income resulting from changes in the fair value of these instruments.  See Note 9 above.

 

 

Fair Value at

 

 

 

 

 

 

(in millions)

 

At December 31, 2018

 

Valuation

Technique

 

Unobservable

Input

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

 

 

 

 

Range (1)

Congestion revenue rights

 

$

203

 

 

$

75

 

 

Market approach

 

CRR auction prices

 

$ (18.61) - 32.26

Power purchase agreements

 

$

 

 

$

33

 

 

Discounted cash flow

 

Forward prices

 

$ 19.81 - 38.80

 

 

 

 

 

 

 

 

 

 

 

(1) Represents price per megawatt-hour

 

 

 

Fair Value at

 

 

 

 

 

 

(in millions)

 

At December 31, 2017

 

Valuation

Technique

 

Unobservable

Input

 

 

Fair Value Measurement

 

Assets

 

Liabilities

 

 

 

 

 

Range (1)

Congestion revenue rights

 

$

129

 

 

$

24

 

 

Market approach

 

CRR auction prices

 

$ (16.03) - 11.99

Power purchase agreements

 

$

 

 

$

63

 

 

Discounted cash flow

 

Forward prices

 

$ 18.81 - 38.80

 

 

 

 

 

 

 

 

 

 

 

(1) Represents price per megawatt-hour

 

Level 3 Reconciliation

 

The following table presents the reconciliation for Level 3 price risk management instruments for the years ended December 31, 2018 and 2017, respectively:

 

Price Risk Management Instruments

(in millions)

2018

 

2017

Asset (liability) balance as of January 1

$

42

 

 

$

55

 

Net realized and unrealized gains:

 

 

 

Included in regulatory assets and liabilities or balancing accounts (1)

53

 

 

(13

)

Asset (liability) balance as of December 31

$

95

 

 

$

42

 

 

 

 

 

(1) The costs related to price risk management activities are fully passed through to customers in rates. Accordingly, unrealized gains and losses are deferred in regulatory liabilities and assets and net income is not impacted.

 

Financial Instruments

 

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value for financial instruments: the fair values of cash, net accounts receivable, short-term borrowings, accounts payable, customer deposits, and the Utility’s variable rate pollution control bond loan agreements approximate their carrying values at December 31, 2018 and 2017, as they are short-term in nature or have interest rates that reset daily.

 

The carrying amount and fair value of PG&E Corporation’s and the Utility’s long-term debt instruments, excluding pollution control bonds, were as follows (the table below excludes financial instruments with carrying values that approximate their fair values):

 

At December 31,

 

2018

 

2017

(in millions)

Carrying Amount

 

Level 2 Fair Value

 

Carrying Amount

 

Level 2 Fair Value

Debt (Note 4)

 

 

 

 

 

 

 

PG&E Corporation(1)

$

350

 

 

$

350

 

 

$

350

 

 

$

350

 

Utility

17,450

 

 

14,747

 

 

17,090

 

 

19,128

 

 

 

 

 

 

 

 

 

(1) On April 26, 2018, PG&E Corporation early redeemed its outstanding $350 million principal amount of 2.40% Senior Notes. Also, in April 2018, PG&E

Corporation entered into a $350 million floating rate unsecured term loan. For more information, see Note 4.

 

 

Nuclear Decommissioning Trust Investments

 

The following table provides a summary of equity securities and available-for-sale debt securities:

(in millions)

Amortized

Cost

 

Total

Unrealized

Gains

 

Total

Unrealized

Losses

 

Total Fair

Value

As of December 31, 2018

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

Short-term investments

$

29

 

 

$

 

 

$

 

 

$

29

 

Global equity securities

568

 

 

1,246

 

 

(5

)

 

1,809

 

Fixed-income securities

1,288

 

 

30

 

 

(18

)

 

1,300

 

Total (1)

$

1,885

 

 

$

1,276

 

 

$

(23

)

 

$

3,138

 

As of December 31, 2017

 

 

 

 

 

 

 

Nuclear decommissioning trusts

 

 

 

 

 

 

 

Short-term investments

$

23

 

 

$

 

 

$

 

 

$

23

 

Global equity securities

524

 

 

1,463

 

 

(2

)

 

1,985

 

Fixed-income securities

1,252

 

 

51

 

 

(8

)

 

1,295

 

Total (1)

$

1,799

 

 

$

1,514

 

 

$

(10

)

 

$

3,303

 

 

 

 

 

 

 

 

 

(1) Represents amounts before deducting $408 million and $440 million at December 31, 2018 and 2017, respectively, primarily related to deferred taxes on appreciation of investment value.

 

The fair value of fixed-income securities by contractual maturity is as follows:

 

As of

(in millions)

December 31, 2018

Less than 1 year

$

60

 

1–5 years

391

 

5–10 years

341

 

More than 10 years

508

 

Total maturities of fixed-income securities

$

1,300

 

 

The following table provides a summary of activity for the fixed-income and equity securities:

(in millions)

2018

 

2017

 

2016

Proceeds from sales and maturities of nuclear decommissioning investments

$

1,412

 

 

$

1,291

 

 

$

1,295

 

Gross realized gains on securities

54

 

 

53

 

 

18

 

Gross realized losses on securities

(24

)

 

(11

)

 

(26

)

 

NOTE 11: EMPLOYEE BENEFIT PLANS

 

Pension Plan and Postretirement Benefits Other than Pensions (“PBOP”)

 

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan for eligible employees hired before December 31, 2012 and a cash balance plan for those eligible employees hired after this date or who made a one-time election to participate (“Pension Plan”).  Certain trusts underlying these plans are qualified trusts under the Internal Revenue Code of 1986, as amended.  If certain conditions are met, PG&E Corporation and the Utility can deduct payments made to the qualified trusts, subject to certain limitations.  PG&E Corporation’s and the Utility’s funding policy is to contribute tax-deductible amounts, consistent with applicable regulatory decisions and federal minimum funding requirements.  On an annual basis, the Utility funds the pension plans up to the amount it is authorized to recover in rates, $327 million for both 2018 and 2017.

 

PG&E Corporation and the Utility also sponsor contributory postretirement medical plans for retirees and their eligible dependents, and non-contributory postretirement life insurance plans for eligible employees and retirees.  PG&E Corporation and the Utility use a fiscal year-end measurement date for all plans.

 

On February 27, 2019, PG&E Corporation and the Utility received approval from the Bankruptcy Court to maintain existing pension and other benefit plans during the pendency of the Chapter 11 Cases. (For more information see "Chapter 11 Proceedings" in Note 15 below.)

 

Change in Plan Assets, Benefit Obligations, and Funded Status

 

The following tables show the reconciliation of changes in plan assets, benefit obligations, and the plans’ aggregate funded status for pension benefits and other benefits for PG&E Corporation during 2018 and 2017:

 

Pension Plan

(in millions)

2018

 

2017

Change in plan assets:

 

 

 

Fair value of plan assets at beginning of year

$

16,652

 

 

$

14,729

 

Actual return on plan assets

(923

)

 

2,380

 

Company contributions

334

 

 

335

 

Benefits and expenses paid

(751

)

 

(792

)

Fair value of plan assets at end of year

$

15,312

 

 

$

16,652

 

 

 

 

 

Change in benefit obligation:

 

 

 

Benefit obligation at beginning of year

$

18,757

 

 

$

17,305

 

Service cost for benefits earned

514

 

 

472

 

Interest cost

687

 

 

714

 

Actuarial (gain) loss

(1,800

)

 

1,048

 

Plan amendments

 

 

10

 

Benefits and expenses paid

(751

)

 

(792

)

Benefit obligation at end of year (1)

$

17,407

 

 

$

18,757

 

 

 

 

 

Funded Status:

 

 

 

Current liability

$

(8

)

 

$

(7

)

Noncurrent liability

(2,087

)

 

(2,098

)

Net liability at end of year

$

(2,095

)

 

$

(2,105

)

 

 

 

 

(1) PG&E Corporation’s accumulated benefit obligation was $15.8 billion and $16.8 billion at December 31, 2018 and 2017, respectively.

 

Postretirement Benefits Other than Pensions

(in millions)

2018

 

2017

Change in plan assets:

 

 

 

Fair value of plan assets at beginning of year

$

2,420

 

 

$

2,173

 

Actual return on plan assets

(108

)

 

298

 

Company contributions

31

 

 

33

 

Plan participant contribution

81

 

 

87

 

Benefits and expenses paid

(166

)

 

(171

)

Fair value of plan assets at end of year

$

2,258

 

 

$

2,420

 

 

 

 

 

Change in benefit obligation:

 

 

 

Benefit obligation at beginning of year

$

1,897

 

 

$

1,877

 

Service cost for benefits earned

66

 

 

59

 

Interest cost

69

 

 

77

 

Actuarial (gain) loss

(221

)

 

(49

)

Benefits and expenses paid

(150

)

 

(157

)

Federal subsidy on benefits paid

3

 

 

3

 

Plan participant contributions

81

 

 

87

 

Benefit obligation at end of year

$

1,745

 

 

$

1,897

 

 

 

 

 

Funded Status: (1)

 

 

 

Noncurrent asset

$

545

 

 

$

553

 

Noncurrent liability

(32

)

 

(30

)

Net asset at end of year

$

513

 

 

$

523

 

 

 

 

 

(1) At December 31, 2018 and 2017, the postretirement medical plan was in an overfunded position and the postretirement life insurance plan was in an underfunded position.

 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

 

Components of Net Periodic Benefit Cost

 

PG&E Corporation and the Utility sponsor a non-contributory defined benefit pension plan and cash balance plan.  Both plans are included in “Pension Benefits” below.  Post-retirement medical and life insurance plans are included in “Other Benefits” below.

 

Net periodic benefit cost as reflected in PG&E Corporation’s Consolidated Statements of Income was as follows:

 

Pension Plan

(in millions)

2018

 

2017

 

2016

Service cost for benefits earned (1)

$

514

 

 

$

472

 

 

$

453

 

Interest cost

687

 

 

714

 

 

715

 

Expected return on plan assets

(1,021

)

 

(770

)

 

(828

)

Amortization of prior service cost

(6

)

 

(7

)

 

8

 

Amortization of net actuarial loss

5

 

 

22

 

 

24

 

Net periodic benefit cost

179

 

 

431

 

 

372

 

Less: transfer to regulatory account (2)

157

 

 

(92

)

 

(34

)

Total expense recognized

$

336

 

 

$

339

 

 

$

338

 

 

 

 

 

 

 

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

(2) The Utility recorded these amounts to a regulatory account as they are probable of recovery from customers in future rates.

 

Postretirement Benefits Other than Pensions

(in millions)

2018

 

2017

 

2016

Service cost for benefits earned (1)

$

66

 

 

$

59

 

 

$

52

 

Interest cost

69

 

 

77

 

 

76

 

Expected return on plan assets

(130

)

 

(97

)

 

(107

)

Amortization of prior service cost

14

 

 

15

 

 

15

 

Amortization of net actuarial loss

(5

)

 

4

 

 

4

 

Net periodic benefit cost

$

14

 

 

$

58

 

 

$

40

 

 

 

 

 

 

 

(1) A portion of service costs are capitalized pursuant to ASU 2017-07.

 

Non-service costs are reflected in Other income, net on the Consolidated Statements of Income. Service costs are reflected in Operating and maintenance on the Consolidated Statements of Income.

 

There was no material difference between PG&E Corporation and the Utility for the information disclosed above.

 

Components of Accumulated Other Comprehensive Income

 

PG&E Corporation and the Utility record unrecognized prior service costs and unrecognized gains and losses related to pension and post-retirement benefits other than pension as components of accumulated other comprehensive income, net of tax.  In addition, regulatory adjustments are recorded in the Consolidated Statements of Income and Consolidated Balance Sheets to reflect the difference between expense or income calculated in accordance with GAAP for accounting purposes and expense or income for ratemaking purposes, which is based on authorized plan contributions.  For pension benefits, a regulatory asset or liability is recorded for amounts that would otherwise be recorded to accumulated other comprehensive income.  For post-retirement benefits other than pension, the Utility generally records a regulatory liability for amounts that would otherwise be recorded to accumulated other comprehensive income.  As the Utility is unable to record a regulatory asset for these other benefits, the charge remains in accumulated other comprehensive income (loss).

 

The estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation in 2019 are as follows:

(in millions)

Pension Plan

 

PBOP Plans

Unrecognized prior service cost

$

(6

)

 

$

14

 

Unrecognized net loss

3

 

 

(3

)

Total

$

(3

)

 

$

11

 

 

There were no material differences between the estimated amounts that will be amortized into net periodic benefit costs for PG&E Corporation and the Utility.

 

Valuation Assumptions

 

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic benefit costs.  The following weighted average year-end assumptions were used in determining the plans’ projected benefit obligations and net benefit cost.

 

Pension Plan

 

PBOP Plans

 

December 31,

 

December 31,

 

2018

 

2017

 

2016

 

2018

 

2017

 

2016

Discount rate

4.35

%

 

3.64

%

 

4.11

%

 

4.29 - 4.37%

 

3.60 - 3.67 %

 

4.05 - 4.19 %

Rate of future compensation increases

3.90

%

 

3.90

%

 

4.00

%

 

 

 

 

 

 

Expected return on plan assets

6.00

%

 

6.20

%

 

5.30

%

 

3.60 - 6.80%

 

3.30 - 7.10%

 

2.80 - 6.00%

 

The assumed health care cost trend rate as of December 31, 2018 was 6.5%, decreasing gradually to an ultimate trend rate in 2027 and beyond of approximately 4.5%.  A one-percentage-point change in assumed health care cost trend rate would have the following effects:

(in millions)

One-Percentage-Point

Increase

 

One-Percentage-Point

Decrease

Effect on postretirement benefit obligation

$

112

 

 

$

(113

)

Effect on service and interest cost

9

 

 

(10

)

 

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit plan trusts, resulting in a weighted average rate of return on plan assets.  Returns on fixed-income debt investments were projected based on real maturity and credit spreads added to a long-term inflation rate.  Returns on equity investments were estimated based on estimates of dividend yield and real earnings growth added to a long-term inflation rate.  For the pension plan, the assumed return of 6.0% compares to a ten-year actual return of 10.0%.  The rate used to discount pension benefits and other benefits was based on a yield curve developed from market data of over approximately 1,101 Aa-grade non-callable bonds at December 31, 2018.  This yield curve has discount rates that vary based on the duration of the obligations.  The estimated future cash flows for the pension benefits and other benefit obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate.

 

Investment Policies and Strategies

 

The financial position of PG&E Corporation’s and the Utility’s funded status is the difference between the fair value of plan assets and projected benefit obligations.  Volatility in funded status occurs when asset values change differently from liability values and can result in fluctuations in costs in financial reporting, as well as the amount of minimum contributions required under the Employee Retirement Income Security Act of 1974, as amended.  PG&E Corporation’s and the Utility’s investment policies and strategies are designed to increase the ratio of trust assets to plan liabilities at an acceptable level of funded status volatility.

 

The trusts’ asset allocations are meant to manage volatility, reduce costs, and diversify its holdings.  Interest rate, credit, and equity risk are the key determinants of PG&E Corporation’s and the Utility’s funded status volatility.  In addition to affecting the trusts’ fixed income portfolio market values, interest rate changes also influence liability valuations as discount rates move with current bond yields.  To manage volatility, PG&E Corporation’s and the Utility’s trusts hold significant allocations in long maturity fixed-income investments. Although they contribute to funded status volatility, equity investments are held to reduce long-term funding costs due to their higher expected return.  Real assets and absolute return investments are held to diversify the trust’s holdings in equity and fixed-income investments by exhibiting returns with low correlation to the direction of these markets. Real assets include commodities futures, global REITS, global listed infrastructure equities, and private real estate funds.  Absolute return investments include hedge fund portfolios.

 

Derivative instruments such as equity index futures are used to meet target equity exposure. Derivative instruments, such as equity index futures and U.S. treasury futures, are also used to rebalance the fixed income/equity allocation of the pension’s portfolio. Foreign currency exchange contracts are used to hedge a portion of the non U.S. dollar exposure of global equity investments.

 

The target asset allocation percentages for major categories of trust assets for pension and other benefit plans are as follows:

 

Pension Plan

 

PBOP Plans

 

2019

 

2018

 

2017

 

2019

 

2018

 

2017

Global equity securities

29

%

 

29

%

 

27

%

 

33

%

 

33

%

 

32

%

Absolute return

5

%

 

5

%

 

5

%

 

3

%

 

3

%

 

3

%

Real assets

8

%

 

8

%

 

10

%

 

6

%

 

6

%

 

7

%

Fixed-income securities

58

%

 

58

%

 

58

%

 

58

%

 

58

%

 

58

%

Total

100

%

 

100

%

 

100

%

 

100

%

 

100

%

 

100

%

 

 

PG&E Corporation and the Utility apply a risk management framework for managing the risks associated with employee benefit plan trust assets.  The guiding principles of this risk management framework are the clear articulation of roles and responsibilities, appropriate delegation of authority, and proper accountability and documentation.  Trust investment policies and investment manager guidelines include provisions designed to ensure prudent diversification, manage risk through appropriate use of physical direct asset holdings and derivative securities, and identify permitted and prohibited investments.

 

Fair Value Measurements

 

The following tables present the fair value of plan assets for pension and other benefits plans by major asset category at December 31, 2018 and 2017.

 

Fair Value Measurements

 

At December 31,

 

2018

 

2017

(in millions)

Level 1

 

Level 2

 

Level 3

 

Total

 

Level 1

 

Level 2

 

Level 3

 

Total

Pension Plan:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

$

333

 

 

$

22

 

 

$

 

 

$

355

 

 

$

287

 

 

$

424

 

 

$

 

 

$

711

 

Global equity securities

1,145

 

 

 

 

 

 

1,145

 

 

1,292

 

 

 

 

 

 

1,292

 

Real assets

461

 

 

 

 

 

 

461

 

 

499

 

 

 

 

 

 

499

 

Fixed-income securities

1,897

 

 

5,216

 

 

8

 

 

7,121

 

 

1,916

 

 

5,520

 

 

4

 

 

7,440

 

Assets measured at NAV

 

 

 

 

 

 

6,202

 

 

 

 

 

 

 

 

6,818

 

Total

$

3,836

 

 

$

5,238

 

 

$

8

 

 

$

15,284

 

 

$

3,994

 

 

$

5,944

 

 

$

4

 

 

$

16,760

 

PBOP Plans:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Short-term investments

$

33

 

 

$

 

 

$

 

 

$

33

 

 

$

31

 

 

$

 

 

$

 

 

$

31

 

Global equity securities

115

 

 

 

 

 

 

115

 

 

141

 

 

 

 

 

 

141

 

Real assets

50

 

 

 

 

 

 

50

 

 

55

 

 

 

 

 

 

55

 

Fixed-income securities

153

 

 

857

 

 

 

 

1,010

 

 

163

 

 

757

 

 

 

 

920

 

Assets measured at NAV

 

 

 

 

 

 

1,056

 

 

 

 

 

 

 

 

1,281

 

Total

$

351

 

 

$

857

 

 

$

 

 

$

2,264

 

 

$

390

 

 

$

757

 

 

$

 

 

$

2,428

 

Total plan assets at fair value

 

 

 

 

 

 

$

17,548

 

 

 

 

 

 

 

 

$

19,188

 

 

In addition to the total plan assets disclosed at fair value in the table above, the trusts had other net liabilities of $22 million and other net assets of $116 million at December 31, 2018 and 2017, respectively, comprised primarily of cash, accounts receivable, deferred taxes, and accounts payable.

 

Valuation Techniques

 

The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the table above.  All investments that are valued using a net asset value per share can be redeemed quarterly with a notice not to exceed 90 days.

 

Short-Term Investments

 

Short-term investments consist primarily of commingled funds across government, credit, and asset-backed sectors. These securities are categorized as Level 1 and Level 2 assets.

 

Global Equity securities

 

The global equity category includes investments in common stock and equity-index futures.  Equity investments in common stock are actively traded on public exchanges and are therefore considered Level 1 assets.  These equity investments are generally valued based on unadjusted prices in active markets for identical securities.  Equity-index futures are valued based on unadjusted prices in active markets and are Level 1 assets.

 

Real Assets

 

The real asset category includes portfolios of commodity futures, global REITS, global listed infrastructure equities, and private real estate funds.  The commodity futures, global REITS, and global listed infrastructure equities are actively traded on a public exchange and are therefore considered Level 1 assets.

 

Fixed-Income securities

 

Fixed-income securities are primarily composed of U.S. government and agency securities, municipal securities, and other fixed-income securities, including corporate debt securities.  U.S. government and agency securities primarily consist of U.S. Treasury securities that are classified as Level 1 because the fair value is determined by observable market prices in active markets.  A market approach is generally used to estimate the fair value of debt securities classified as Level 2 using evaluated pricing data such as broker quotes, for similar securities adjusted for observable differences.  Significant inputs used in the valuation model generally include benchmark yield curves and issuer spreads.  The external credit ratings, coupon rate, and maturity of each security are considered in the valuation model, as applicable.

 

Assets Measured at NAV Using Practical Expedient

 

Investments in the trusts that are measured at fair value using the NAV per share practical expedient have not been classified in the fair value hierarchy tables above. The fair value amounts are included in the tables above in order to reconcile to the amounts presented in the Consolidated Balance Sheets. These investments include commingled funds that are composed of equity securities traded publicly on exchanges as well as fixed-income securities that are composed primarily of U.S. government securities, asset-backed securities, and private real estate funds. There are no restrictions on the terms and conditions upon which the investments may be redeemed.

 

Transfers Between Levels

 

Any transfers between levels in the fair value hierarchy are recognized as of the end of the reporting period.  No material transfers between levels occurred in the years ended December 31, 2018 and 2017.

 

Level 3 Reconciliation

 

The following table is a reconciliation of changes in the fair value of instruments for the pension plan that have been classified as Level 3 for the years ended December 31, 2018 and 2017:

(in millions)

 

For the year ended December 31, 2018

Fixed-Income

Balance at beginning of year

$

4

 

Actual return on plan assets:

 

Relating to assets still held at the reporting date

(3

)

Relating to assets sold during the period

 

Purchases, issuances, sales, and settlements:

 

Purchases

6

 

Settlements

1

 

Balance at end of year

$

8

 

 

 

(in millions)

 

For the year ended December 31, 2017

Fixed-Income

Balance at beginning of year

$

5

 

Actual return on plan assets:

 

Relating to assets still held at the reporting date

(1

)

Relating to assets sold during the period

 

Purchases, issuances, sales, and settlements:

 

Purchases

3

 

Settlements

(3

)

Balance at end of year

$

4

 

 

 

There were no material transfers out of Level 3 in 2018 and 2017.

 

Cash Flow Information

 

Employer Contributions

 

PG&E Corporation and the Utility contributed $334 million to the pension benefit plans and $31 million to the other benefit plans in 2018.  These contributions are consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax-deductible and consistent with applicable regulatory decisions and federal minimum funding requirements.  None of these pension or other benefits were subject to a minimum funding requirement requiring a cash contribution in 2018.  The Utility’s pension benefits met all the funding requirements under Employee Retirement Income Security Act.  PG&E Corporation and the Utility expect to make total contributions of approximately $327 million and $24 million to the pension plan and other postretirement benefit plans, respectively, for 2019.

 

Benefits Payments and Receipts

 

As of December 31, 2018, the estimated benefits expected to be paid and the estimated federal subsidies expected to be received in each of the next five fiscal years, and in aggregate for the five fiscal years thereafter, are as follows:

(in millions)

Pension

Plan

 

PBOP

Plans

 

Federal

Subsidy

2019

778

 

 

88

 

 

(8

)

2020

855

 

 

91

 

 

(9

)

2021

891

 

 

94

 

 

(9

)

2022

925

 

 

99

 

 

(3

)

2023

957

 

 

102

 

 

(3

)

Thereafter in the succeeding five years

5,136

 

 

507

 

 

(12

)

 

There were no material differences between the estimated benefits expected to be paid by PG&E Corporation and paid by the Utility for the years presented above.  There were also no material differences between the estimated subsidies expected to be received by PG&E Corporation and received by the Utility for the years presented above.

 

Retirement Savings Plan

 

PG&E Corporation sponsors a retirement savings plan, which qualifies as a 401(k) defined contribution benefit plan under the Internal Revenue Code 1986, as amended.  This plan permits eligible employees to make pre-tax and after-tax contributions into the plan, and provide for employer contributions to be made to eligible participants.  Total expenses recognized for defined contribution benefit plans reflected in PG&E Corporation’s Consolidated Statements of Income were $105 million, $103 million, and $97 million in 2018, 2017, and 2016, respectively.

 

There were no material differences between the employer contribution expense for PG&E Corporation and the Utility for the years presented above.

 

NOTE 12: RELATED PARTY AGREEMENTS AND TRANSACTIONS

 

The Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves.  The Utility and PG&E Corporation exchange administrative and professional services in support of operations.  Services provided directly to PG&E Corporation by the Utility are priced at the higher of fully loaded cost (i.e., direct cost of good or service and allocation of overhead costs) or fair market value, depending on the nature of the services.  Services provided directly to the Utility by PG&E Corporation are generally priced at the lower of fully loaded cost or fair market value, depending on the nature and value of the services.  PG&E Corporation also allocates various corporate administrative and general costs to the Utility and other subsidiaries using agreed-upon allocation factors, including the number of employees, operating and maintenance expenses, total assets, and other cost allocation methodologies.  Management believes that the methods used to allocate expenses are reasonable and meet the reporting and accounting requirements of its regulatory agencies.

 

The Utility’s significant related party transactions were:

 

Year Ended December 31,

(in millions)

2018

 

2017

 

2016

Utility revenues from:

 

 

 

 

 

Administrative services provided to PG&E Corporation

$

4

 

 

$

8

 

 

$

7

 

Utility expenses from:

 

 

 

 

 

Administrative services received from PG&E Corporation

$

94

 

 

$

65

 

 

$

74

 

Utility employee benefit due to PG&E Corporation

76

 

 

73

 

 

91

 

 

At December 31, 2018 and 2017, the Utility had receivables of $33 million and $20 million, respectively, from PG&E Corporation included in accounts receivable – other and other noncurrent assets – other on the Utility’s Consolidated Balance Sheets, and payables of $38 million and $22 million, respectively, to PG&E Corporation included in accounts payable – other on the Utility’s Consolidated Balance Sheets.

 

NOTE 13: WILDFIRE-RELATED CONTINGENCIES

 

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to wildfires. A provision for a loss contingency is recorded when it is both probable that a liability has been incurred and the amount of the liability can be reasonably estimated. PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses and record a charge that reflects their best estimate or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events. Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter. PG&E Corporation's and the Utility's provision for loss and expense excludes anticipated legal costs, which are expensed as incurred. PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

 

Wildfire-Related Claims

 

Wildfire-related claims on the Consolidated Financial Statements include amounts associated with the 2018 Camp fire, the 2017 Northern California wildfires, and the 2015 Butte fire.

 

For the years ended December 31, 2018, 2017 and 2016, the Utility’s Consolidated Income Statements include estimated losses offset by insurance recoveries as follows:

 

Year Ended December 31,

(in millions)

2018

 

2017

 

2016

2015 Butte fire

 

 

 

 

 

Third-Party Claims

$

 

 

$

350

 

 

$

750

 

Insurance recoveries

(7

)

 

(350

)

 

(625

)

Total 2015 Butte fire

(7

)

 

 

 

125

 

2017 Northern California wildfires

 

 

 

 

 

Third-Party Claims

3,500

 

 

 

 

 

Insurance recoveries

(842

)

 

 

 

 

Total 2017 Northern California wildfires

2,658

 

 

 

 

 

2018 Camp fire

 

 

 

 

 

Third-Party Claims

10,500

 

 

 

 

 

Insurance recoveries

(1,380

)

 

 

 

 

Total 2018 Camp fire

9,120

 

 

 

 

 

Total wildfire-related claims, net of insurance recoveries

$

11,771

 

 

$

 

 

$

125

 

 

 

In addition to the amounts shown in the table above, during the year ended December 31, 2018, the Utility incurred $245 million of legal and other costs related to the 2018 Camp fire, the 2017 Northern California wildfires and the 2015 Butte fire.

 

At December 31, 2018 and 2017, the Utility's Consolidated Balance Sheets include estimated liabilities as follows:

 

Balance At

(in millions)

December 31, 2018

 

December 31, 2017

2015 Butte fire

$

226

 

 

$

561

 

2017 Northern California wildfires

3,500

 

 

 

2018 Camp fire

10,500

 

 

 

Total wildfire-related claims

$

14,226

 

 

$

561

 

 

2018 Camp Fire Background

 

On November 8, 2018, a wildfire began near the city of Paradise, Butte County, California (the “2018 Camp fire”), which is located in the Utility’s service territory. Cal Fire's Camp Fire Incident Information Website as of January 4, 2019, (the “Cal Fire website”), indicated that the 2018 Camp fire consumed 153,336 acres. On the Cal Fire website, Cal Fire reported 86 fatalities and the destruction of 13,972 residences, 528 commercial structures and 4,293 other buildings resulting from the 2018 Camp fire. On February 7, 2019, the Butte County Sheriff's Office reported that the number of fatalities resulting from the 2018 Camp fire had been reduced from 86 to 85.

 

Although the cause of the 2018 Camp fire is still under investigation, based on the information currently known to PG&E Corporation and the Utility and reported to the CPUC and other agencies, including the facts described below, PG&E Corporation and the Utility believe it is probable that the Utility’s equipment will be determined to be an ignition point of the 2018 Camp fire.

 

The Utility submitted two Electric Incident Reports (the “EIRs”) to the CPUC: one on November 8, 2018 and one on November 16, 2018. On December 11, 2018, the Utility publicly released a letter to the CPUC supplementing the EIRs (the “20-Day Electric Incident Report”), which stated:

 

  • On Cal Fire’s website, Cal Fire has identified coordinates for the 2018 Camp fire near Tower :27/222 on the Utility’s Caribou-Palermo 115 kV Transmission Line and has identified the start time of the 2018 Camp fire as 6:33 a.m. on November 8, 2018.

 

  • On November 8, 2018, at approximately 6:15 a.m., the Utility’s Caribou-Palermo 115kV Transmission Line relayed and deenergized. At approximately 6:30 a.m. that day, a Utility employee observed fire in the vicinity of Tower :27/222, and this observation was reported to 911 by Utility employees. In the afternoon of November 8, the Utility observed damage on the line at Tower :27/222. Specifically, an aerial patrol identified that a suspension insulator supporting a transposition jumper had separated from an arm on Tower :27/222.

 

  • On November 14, 2018, the Utility observed a broken C-hook attached to the separated suspension insulator that had connected the suspension insulator to a tower arm, along with wear at the connection point. In addition, the Utility observed a flash mark on Tower :27/222 near where the transposition jumper was suspended and damage to the transposition jumper and suspension insulator.

 

  • In addition to the events on the Caribou-Palermo 115kV Transmission Line, on November 8, 2018, at approximately 6:45 a.m., the Utility’s Big Bend 1101 12 kV Circuit experienced an outage. On November 9, 2018, a Utility employee on patrol arrived at the location of the pole with Line Recloser (“LR”) 1704 on the Big Bend 1101 Circuit and observed that the pole and other equipment were on the ground with bullets and bullet holes at the break point of the pole and on the equipment. On November 12, 2018, a Utility employee was patrolling Concow Road north of LR 1704 when he observed wires down and damaged and downed poles at the intersection of Concow Road and Rim Road. At this location, the employee observed several snapped trees, with some on top of the downed wires.

 

The information contained in the EIRs and the 20-Day Electric Incident Report is factual and preliminary and does not reflect a determination of the causes of the 2018 Camp fire. These incidents remain under investigation by Cal Fire and the CPUC. With respect to the potential ignition point on the Utility’s Big Bend 1101 12 kV Circuit, although Cal Fire has identified this location as a potential ignition point, based on the condition of the site, PG&E Corporation and the Utility have not been able to determine whether the Big Bend 1101 12 kV Circuit may be a probable ignition point for the 2018 Camp fire. Neither Cal Fire nor the CPUC has publicly issued any news releases or other determinations for the 2018 Camp fire. The timing and outcome of the investigations are uncertain. PG&E Corporation and the Utility are cooperating with Cal Fire and the CPUC.

 

Further, the CPUC’s SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating the fire. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

 

2017 Northern California Wildfires Background

 

Beginning on October 8, 2017, multiple wildfires spread through Northern California, including Napa, Sonoma, Butte, Humboldt, Mendocino, Lake, Nevada, and Yuba Counties, as well as in the area surrounding Yuba City (the “2017 Northern California wildfires”). According to the Cal Fire California Statewide Fire Summary dated October 30, 2017, at the peak of the 2017 Northern California wildfires, there were 21 major fires that, in total, burned over 245,000 acres and destroyed an estimated 8,900 structures. The 2017 Northern California wildfires resulted in 44 fatalities.

 

Cal Fire has issued its determination on the causes of 19 of the 2017 Northern California wildfires, and alleged that all of these fires, with the exception of the Tubbs fire, involved the Utility's equipment. The remaining wildfires remain under Cal Fire's investigation, including the possible role of the Utility's power lines and other facilities.

 

During the second quarter of 2018, Cal Fire issued news releases announcing its determination on the causes of 16 of the 2017 Northern California wildfires (the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, 37, Blue, Norrbom, Adobe, Partrick, Pythian, Nuns, Pocket and Atlas fires, located in Mendocino, Lake, Butte, Sonoma, Humboldt, Nevada and Napa counties). According to the Cal Fire news releases, the first four fires “were caused by trees coming into contact with power lines” and the remaining 12 fires “were caused by electric power and distribution lines, conductors and the failure of power poles.” Cal Fire has not yet released its investigation reports related to the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires and stated in its news releases that these investigations have been referred to the appropriate county District Attorney’s offices for review “due to evidence of alleged violations of state law.” The Butte County District Attorney's office has entered into a settlement agreement with the Utility, resolving the Honey, Cherokee and LaPorte fire allegations without criminal or civil charges. The timing and outcome for resolution of the remaining referrals are uncertain.

 

Also during the second quarter of 2018, Cal Fire released its investigation reports related to the Redwood, Cherokee, 37, Nuns and La Porte fires. Cal Fire did not refer these fires to District Attorney offices for investigation.

 

On October 9, 2018, Cal Fire issued a news release announcing the results of its investigation into the Cascade fire, located in Yuba County, concluding that the Cascade fire “was started by sagging power lines coming into contact during heavy winds” and that “the power line in question was owned by Pacific Gas and Electric Company.” On October 10, 2018, Cal Fire released its investigation report related to the Cascade fire.

 

On January 24, 2019, Cal Fire issued a news release and its investigation report into the cause of the Tubbs fire. Cal Fire has determined that the Tubbs fire was caused by a private electrical system adjacent to a residential structure.

 

Cal Fire has not publicly issued any news releases or other determinations for the Maacama, Pressley and Point wildfires. The timing and outcome of the Cal Fire investigation into these fires is uncertain.

 

Further, the SED is conducting investigations to assess the compliance of electric and communication companies’ facilities with applicable rules and regulations in fire-impacted areas. According to information made available by the CPUC, investigation topics include, but are not limited to, maintenance of facilities, vegetation management, and emergency preparedness and response. Various other entities, including fire departments, may also be investigating certain of the fires. It is uncertain when the investigations will be complete and whether the SED will release any preliminary findings before its investigations are complete.

 

The Utility has submitted 23 electric incident reports to the CPUC associated with the 2017 Northern California wildfires where Cal Fire or the Utility has identified a site as potentially involving the Utility’s facilities in its investigation and the property damage associated with each incident exceeded $50,000. The information contained in these reports is factual and preliminary and does not reflect a determination of the causes of the fires.

 

Third-Party Claims, Investigations and Other Proceedings Related to the 2018 Camp Fire and 2017 Northern California Wildfires

 

If the Utility’s facilities, such as its electric distribution and transmission lines, are determined to be the substantial cause of one or more fires, and the doctrine of inverse condemnation applies, the Utility could be liable for property damage, business interruption, interest and attorneys’ fees without having been found negligent. California courts have imposed liability under the doctrine of inverse condemnation in legal actions brought by property holders against utilities on the grounds that losses borne by the person whose property was damaged through a public use undertaking should be spread across the community that benefited from such undertaking, and based on the assumption that utilities have the ability to recover these costs from their customers. Further, California courts have determined that the doctrine of inverse condemnation is applicable regardless of whether the CPUC ultimately allows recovery by the utility for any such costs. The CPUC may decide not to authorize cost recovery even if a court decision were to determine that the Utility is liable as a result of the application of the doctrine of inverse condemnation. (See “Loss Recoveries-Regulatory Recovery” below for further information regarding potential cost recovery related to the wildfires, including in connection with SB 901.)

 

In addition to claims for property damage, business interruption, interest and attorneys’ fees, the Utility could be liable for fire suppression costs, evacuation costs, medical expenses, personal injury damages, punitive damages and other damages under other theories of liability, including if the Utility were found to have been negligent.

 

Further, the Utility could be subject to material fines or penalties if the CPUC or any law enforcement agency brought an enforcement action, including a criminal proceeding, and determined that the Utility failed to comply with applicable laws and regulations.

 

As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 100 complaints on behalf of at least 4,200 plaintiffs related to the 2018 Camp fire, nine of which seek to be certified as class actions. The pending civil litigation against PG&E Corporation and the Utility related to the 2018 Camp fire, which is currently stayed as a result of the commencement of the Chapter 11 Cases, includes claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance, public nuisance, negligence, negligence per se, negligent interference with prospective economic advantage, negligent infliction of emotional distress, premises liability, violations of the Public Utilities Code, violations of the Health & Safety Code, malice and false advertising in violation of the California Business and Professions Code. The plaintiffs principally assert that PG&E Corporation's and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2018 Camp fire. The plaintiffs seek damages and remedies that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, establishment of a class action medical monitoring fund, punitive damages, attorneys’ fees and other damages. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

 

As of January 28, 2019, PG&E Corporation and the Utility are aware of approximately 750 complaints on behalf of at least 3,800 plaintiffs related to the 2017 Northern California wildfires, five of which seek to be certified as class actions. These cases have been coordinated in the San Francisco County Superior Court. As of the Petition Date, the coordinated litigation was in the early stages of discovery. A trial with respect to the Atlas fire was scheduled to begin on September 23, 2019. The pending civil litigation against PG&E Corporation and the Utility related to the 2017 Northern California wildfires, includes claims under multiple theories of liability, including inverse condemnation, trespass, private nuisance and negligence. This litigation, including the trial date with respect to the Atlas fire, currently is stayed as a result of the commencement of the Chapter 11 Cases. The plaintiffs principally assert that PG&E Corporation's and the Utility’s alleged failure to maintain and repair their distribution and transmission lines and failure to properly maintain the vegetation surrounding such lines were the causes of the 2017 Northern California wildfires. The plaintiffs seek damages that include wrongful death, personal injury, property damage, evacuation costs, medical expenses, punitive damages, attorneys’ fees and other damages. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

 

Insurance carriers who have made payments to their insureds for property damage arising out of the 2017 Northern California wildfires have filed 48 subrogation complaints in the San Francisco County Superior Court as of January 28, 2019. These complaints allege, among other things, negligence, inverse condemnation, trespass and nuisance. The allegations are similar to the ones made by individual plaintiffs. As of January 28, 2019, insurance carriers have filed 37 similar subrogation complaints with respect to the 2018 Camp fire in the Sacramento County Superior Court. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

 

Various government entities, including Yuba, Nevada, Lake, Mendocino, Napa and Sonoma Counties and the Cities of Santa Rosa and Clearlake, also have asserted claims against PG&E Corporation and the Utility based on the damages that these government entities allegedly suffered as a result of the 2017 Northern California wildfires. Such alleged damages include, among other things, loss of natural resources, loss of public parks, property damages and fire suppression costs. The causes of action and allegations are similar to the ones made by individual plaintiffs and the insurance carriers. With respect to the 2018 Camp fire, Butte County has filed similar claims against PG&E Corporation and the Utility, and PG&E Corporation and the Utility expect additional similar claims to be made by other government entities. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

 

On March 16, 2018, PG&E Corporation and the Utility filed a demurrer to the inverse condemnation cause of action in the 2017 Northern California wildfires litigation. On May 21, 2018, the court overruled the motion. On July 20, 2018, PG&E Corporation and the Utility filed a writ in the Court of Appeal requesting appellate review of the trial court's decision, which was denied on September 17, 2018. On September 27, 2018, PG&E Corporation and the Utility filed a petition for review to the California Supreme Court. On November 14, 2018, the California Supreme Court denied PG&E Corporation's and the Utility's petition for review.

 

PG&E Corporation and the Utility expect to be the subject of numerous additional claims in connection with the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process.

 

PG&E Corporation and the Utility also are the subject of criminal investigations or other actions by the county District Attorneys to whom Cal Fire has referred its investigations into the McCourtney, Lobo, Sulphur, Blue, Norrbom, Adobe, Partrick, Pythian, Pocket and Atlas fires. Although the Honey fire was referred to the Butte County District Attorney’s Office, in October 2018, the Utility reached an agreement to settle any civil claims or criminal charges that could have been brought by the Butte County District Attorney in connection with the Honey fire, as well as the La Porte and Cherokee fires (which were not referred). The settlement provides for funding by the Utility for at least four years of an enhanced fire prevention and communication program, in the amount of up to $1.5 million, not recoverable in rates. On October 9, 2018, the District Attorney of Yuba County announced his decision not to pursue criminal charges at such time against PG&E Corporation or the Utility pertaining to the Cascade fire. The Office of the District Attorney of Yuba County also indicated that it “reserves the right to review any additional information or evidence that may be submitted to it prior to the expiration of the criminal statute of limitations.”

 

Also in October 2018, the Utility and the Sonoma, Napa, Lake, Humboldt and Nevada County District Attorneys entered into agreements under which the Utility agreed to waive any applicable statutes of limitation related to the 2017 Northern California wildfires that started in these counties for a period of six months, until April 8, 2019. PG&E Corporation and the Utility anticipate further discussions with the District Attorneys in these counties relating to the 2017 Northern California wildfires and whether any criminal or civil charges should be brought. In addition, the Butte County District Attorney’s Office and the California Attorney General’s Office have opened a criminal investigation of the 2018 Camp fire. Additional investigations and other actions may arise out of the other 2017 Northern California wildfires and the 2018 Camp fire. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

 

PG&E Corporation and the Utility are continuing to review the evidence concerning the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility have not yet had access to all of the evidence collected by Cal Fire as part of its investigations or to the many investigation reports prepared by Cal Fire. PG&E Corporation and the Utility and plaintiffs are in discussions with Cal Fire about access to the evidence and the remaining reports. No schedule on gaining access has been set.

 

Regardless of any determinations of cause by Cal Fire with respect to any pre-petition fire, ultimately PG&E Corporation’s and the Utility’s liability will be resolved through the Chapter 11 process, regulatory proceedings and any potential enforcement proceedings, all of which could take a number of years to resolve. The timing and outcome of these and other potential proceedings are uncertain.

 

Potential Losses in Connection with the 2018 Camp Fire and 2017 Northern California Wildfires

 

On January 28, 2019, the California Department of Insurance issued a news release announcing an update on property losses in connection with the 2018 wildfires in Southern California (which are not in the Utility’s service territory) and the 2018 Camp fire, stating that, as of such date, “more than $11.4 billion in insured losses have been reported from the November 2018 fires,” of which approximately $8.4 billion relates to statewide claims from the 2018 Camp fire. On September 6, 2018, the California Department of Insurance issued a news release announcing that insurers have received nearly 55,000 insurance claims totaling more than $12.28 billion in losses, of which approximately $10 billion relates to statewide claims from the 2017 Northern California wildfires.

 

The dollar amounts announced by the California Department of Insurance represent an aggregate amount of approximately $18.4 billion of insurance claims made as of the above dates related to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation and the Utility expect that additional claims have been submitted and will continue to be submitted to insurers, particularly with respect to the 2018 Camp fire. These claims reflect insured property losses only. The $18.4 billion of insurance claims made as of the above dates does not account for uninsured or underinsured property losses, interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses or other costs, such as potential punitive damages, fines or penalties, or losses related to claims that have not manifested yet ("future claims"), each of which could be significant. The scope of all claims related to the 2018 Camp fire and 2017 Northern California wildfires is not known at this time because of the applicable statutes of limitations under California law.

 

Potential liabilities related to the 2018 Camp fire and 2017 Northern California wildfires depend on various factors, including but not limited to the cause of each fire, contributing causes of the fires (including alternative potential origins, weather and climate related issues), the number, size and type of structures damaged or destroyed, the contents of such structures and other personal property damage, the number and types of trees damaged or destroyed, attorneys’ fees for claimants, the nature and extent of any personal injuries, including the loss of lives, the extent to which future claims arise, the amount of fire suppression and clean-up costs, other damages the Utility may be responsible for if found negligent, and the amount of any penalties or fines that may be imposed by governmental entities.

 

There are a number of unknown facts and legal considerations that may impact the amount of any potential liability. Among other things, it is uncertain at this time as to the number of wildfire-related claims that will be filed in the Chapter 11 Cases, the number of current and future claims that will be allowed by the Bankruptcy Court, how claims for punitive damages and claims by variously situated persons will be treated and whether such claims will be allowed, and the impact that historical settlement values for wildfire claims may have on the estimation of wildfire liability in the Chapter 11 Cases. If PG&E Corporation and the Utility were to be found liable for certain or all of the costs, expenses and other losses described above with respect to the 2018 Camp fire and 2017 Northern California wildfires, the amount of such liability could exceed $30 billion, which amount does not include potential punitive damages, fines and penalties or damages related to future claims. This estimate is based on a wide variety of data and other information available to PG&E Corporation and the Utility and their advisors, including various precedents involving similar claims, and accounts for property losses (including insured, uninsured and underinsured property losses), interest, attorneys’ fees, fire suppression and clean-up costs, evacuation costs, personal injury or wrongful death damages, medical expenses and certain other costs. This estimate is not intended to provide an upper end of the range of potential liability arising from the 2018 Camp fire and 2017 Northern California wildfires. In certain circumstances, PG&E Corporation’s and the Utility’s liability could be substantially greater than such amount.

 

If PG&E Corporation and the Utility were to be found liable for any punitive damages or subject to fines or penalties, the amount of such punitive damages, fines and penalties could be significant. PG&E Corporation and the Utility have received significant fines and penalties in connection with past incidents. For example, in 2015, the CPUC approved a decision that imposed penalties on the Utility totaling $1.6 billion in connection with the natural gas explosion that occurred in the City of San Bruno, California on September 9, 2010 (the “San Bruno explosion”). These penalties represented nearly three times the underlying liability for the San Bruno explosion of approximately $558 million incurred for third-party claims, exclusive of shareholder derivative lawsuits and legal costs incurred. The amount of punitive damages, fines and penalties imposed on PG&E Corporation and the Utility could likewise be a significant amount in relation to the underlying liabilities with respect to the 2018 Camp fire and 2017 Northern California wildfires. PG&E Corporation's and the Utility's obligations with respect to such claims are expected to be determined through the Chapter 11 process. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

 

2018 Camp Fire and 2017 Northern California Wildfires Accounting Charge

 

Following accounting rules, PG&E Corporation and the Utility record a liability when a loss is probable and reasonably estimable. In accordance with U.S. generally accepted accounting principles, PG&E Corporation and the Utility evaluate which potential liabilities are probable and the related range of reasonably estimated losses, and record a charge that is the amount within the range that is a better estimate than any other amount or the lower end of the range, if there is no better estimate. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of losses is estimable, often involves a series of complex judgments about future events.

 

2018 Camp Fire

 

In light of the current state of the law and the information currently available to the Utility, including, among other things, the facts described in the EIRs and the 20-Day Electric Incident Report, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with the 2018 Camp fire, and accordingly PG&E Corporation and the Utility recorded a charge in the amount of $10.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation's and the Utility’s reasonably estimated losses, and is subject to change based on additional information.

 

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2018 Camp fire and 2017 Northern California wildfires will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

 

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2018 Camp fire may change, which could result in material increases to the loss accrued.

 

The $10.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant.

 

2017 Northern California Wildfires

 

In light of the current state of the law on inverse condemnation and the information currently available to the Utility, including, among other things, the Cal Fire determinations of cause as stated in Cal Fire’s press releases and their released reports, PG&E Corporation and the Utility have determined that it is probable they will incur a loss for claims in connection with 17 of the 2017 Northern California wildfires referred to as the La Porte, McCourtney, Lobo, Honey, Redwood, Sulphur, Cherokee, Blue, Pocket, Atlas, Cascade, Point and Sonoma/Napa merged fires (which include the Nuns, Norrbom, Adobe, Partrick and Pythian fires). Accordingly, PG&E Corporation and the Utility recorded a charge in the amount of $2.5 billion during the quarter ended June 30, 2018 and a charge in the amount of $1.0 billion during the quarter ended December 31, 2018, for a total charge in the amount of $3.5 billion for the year ended December 31, 2018. This charge corresponds to the lower end of the range of PG&E Corporation’s and the Utility’s reasonably estimated losses and is subject to change based on additional information. The additional charge recorded in the quarter ended December 31, 2018 resulted from additional information obtained by the Utility during that period about the fires.

 

PG&E Corporation and the Utility currently believe that it is reasonably possible that the amount of the loss related to the 2017 Northern California wildfires and the 2018 Camp fire will be greater than the amount accrued, but are unable to reasonably estimate the additional loss and the upper end of the range because there are a number of unknown facts and legal considerations that may impact the amount of any potential liability, including the total scope and nature of claims that may be asserted against PG&E Corporation and the Utility. PG&E Corporation and the Utility intend to continue to review the available information and other information as it becomes available, including evidence in Cal Fire’s possession, evidence from or held by other parties, claims that have not yet been submitted, and additional information about the nature and extent of personal and business property damage and losses, the nature, number and severity of personal injuries, and information made available through the discovery process.

 

The process for estimating losses associated with claims requires management to exercise significant judgment based on a number of assumptions and subjective factors, including but not limited to factors identified above and estimates based on currently available information and prior experience with wildfires. As more information becomes available, management estimates and assumptions regarding the financial impact of the 2017 Northern California wildfires may change, which could result in material increases to the loss accrued.

 

The $3.5 billion charge does not include any amounts for potential penalties or fines that may be imposed by governmental entities on PG&E Corporation or the Utility, or punitive damages, if any, or any losses related to future claims for damages that have not manifested yet, each of which could be significant.

 

The $3.5 billion charge also does not include any amounts in connection with the 37, Tubbs, Maacama and Pressley fires because at this time PG&E Corporation and the Utility have not concluded that a loss arising from those fires is probable. However, in the future it is possible that facts could emerge that lead PG&E Corporation and the Utility to believe that a loss is probable, resulting in the accrual of a liability at that time, the amount of which could be significant.

 

Loss Recoveries

 

PG&E Corporation and the Utility had insurance coverage for liabilities, including wildfire. Additionally, there are several mechanisms that allow for recovery of costs from customers. Potential for recovery is described below. Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows. In addition, the inability to recover costs in in a timely manner could have a material effect on PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows.

 

Insurance

 

PG&E Corporation and the Utility had $842 million of insurance coverage for liabilities, including wildfire events, for the period from August 1, 2017 through July 31, 2018, subject to an initial self-insured retention of $10 million per occurrence and further retentions of approximately $40 million per occurrence. During the third quarter of 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. PG&E Corporation and the Utility expect to face increasing difficulty securing liability insurance in future years due to availability and to face significantly increased insurance costs.

 

PG&E Corporation and the Utility record a receivable for insurance recoveries when it is deemed probable that recovery of a recorded loss will occur. Through December 31, 2018, PG&E Corporation and the Utility recorded $1.38 billion for probable insurance recoveries in connection with the 2018 Camp fire and $842 million for probable insurance recoveries in connection with the 2017 Northern California wildfires. These amounts reflect an assumption that the cause of each fire is deemed to be a separate occurrence under the insurance policies. The amount of the receivable is subject to change based on additional information. PG&E Corporation and the Utility intend to seek full recovery for all insured losses and believe it is reasonably possible that they will record a receivable for the full amount of the insurance limits in the future.

 

If PG&E Corporation and the Utility are unable to recover the full amount of their insurance, or if insurance is otherwise unavailable, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected. Even if PG&E Corporation and the Utility were to recover the full amount of their insurance, PG&E Corporation and the Utility expect their losses in connection with the 2018 Camp fire and 2017 Northern California wildfires will greatly exceed their available insurance.

 

The following table presents changes in the insurance receivable for the year ended December 31, 2018. The balance for insurance receivable is included in Other accounts receivable in PG&E Corporation's and the Utility's Consolidated Balance Sheets:

(in millions)

Insurance Receivable

2018 Camp fire

 

Accrued insurance recoveries

$

1,380

 

Reimbursements

 

Balance at December 31, 2018

$

1,380

 

 

 

2017 Northern California wildfires

 

Accrued insurance recoveries

$

842

 

Reimbursements

(13

)

Balance at December 31, 2018

$

829

 

 

Regulatory Recovery

 

On June 21, 2018, the CPUC issued a decision granting the Utility’s request to establish a WEMA to track specific incremental wildfire liability costs effective as of July 26, 2017. The decision does not grant the Utility rate recovery of any wildfire-related costs. Any such rate recovery would require CPUC authorization in a separate proceeding. The Utility may be unable to fully recover costs in excess of insurance, if at all. Rate recovery is uncertain, therefore the Utility has not recorded a regulatory asset related to any wildfire claims costs. Even if such recovery is possible, it could take a number of years to resolve and a number of years to collect.

 

In addition, SB 901, signed into law on September 21, 2018, requires the CPUC to establish a customer harm threshold, directing the CPUC to limit certain disallowances in the aggregate, so that they do not exceed the maximum amount that the Utility can pay without harming ratepayers or materially impacting its ability to provide adequate and safe service (the “Customer Harm Threshold”). SB 901 also authorizes the CPUC to issue a financing order that permits recovery, through the issuance of recovery bonds (also referred to as “securitization”), of wildfire-related costs found to be just and reasonable by the CPUC and, only for the 2017 Northern California wildfires, any amounts in excess of the Customer Harm Threshold. SB 901 does not authorize securitization with respect to possible 2018 Camp fire costs, as the bill does not address fires that occurred in 2018.

 

On January 10, 2019, the CPUC adopted an OIR, which establishes a process to develop criteria and a methodology to inform determinations of the Customer Harm Threshold in future applications under Section 451.2(a) of the Public Utilities Code for cost recovery of 2017 wildfire costs. In the OIR, the CPUC stated that “consistent with Section 451.2(a), the determination of what costs and expenses are just and reasonable must be made in the context of an application for the recovery of specific costs related to the 2017 wildfires.” Following the CPUC’s interpretation of Section 451.2 as outlined in the OIR, PG&E Corporation and the Utility believe that any securitization of costs relating to the 2017 Northern California wildfires would not occur, if at all, until (a) the Utility has paid claims relating to the 2017 Northern California wildfires, (b) the Utility has filed application for recovery of such costs and (c) the CPUC makes a determination that such costs are just and reasonable or in excess of the Customer Harm Threshold. PG&E Corporation and the Utility therefore do not expect the CPUC to permit the Utility to securitize costs relating to the 2017 Northern California wildfires on an expedited or emergency basis unless the CPUC alters the position expressed in the OIR.

 

On February 11, 2019, PG&E Corporation and the Utility filed opening comments in response to the OIR in which they argued, among other things, the CPUC should (1) promptly set a Customer Harm Threshold, or at least define the methodology for setting the Customer Harm Threshold with sufficient specificity to enable PG&E Corporation and the Utility and potential investors to anticipate that amount; (2) determine the Customer Harm Threshold based on the capital needed to resolve claims arising from both the 2018 Camp fire and 2017 Northern California wildfires to be provided for in a plan of reorganization; (3) define how the Customer Harm Threshold will be applied to any future wildfires; and (4) establish the Customer Harm Threshold based on the amount of debt PG&E Corporation and the Utility can raise. Based on assumptions set forth in the comments, PG&E Corporation and the Utility indicated that they could borrow up to approximately $3 billion to fund wildfire claims costs as part of a plan of reorganization.

 

Failure to obtain a substantial or full recovery of costs related to the 2018 Camp fire and 2017 Northern California wildfires or any conclusion that such recovery is no longer probable could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity and cash flows.

 

Wildfire-Related Derivative Litigation

 

Two purported derivative lawsuits alleging claims for breach of fiduciary duties and unjust enrichment were filed in the San Francisco County Superior Court on November 16, 2017 and November 20, 2017, respectively, naming as defendants current and certain former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation and the Utility are named as nominal defendants. These lawsuits were consolidated by the court on February 14, 2018, and are denominated In Re California North Bay Fire Derivative Litigation. On April 13, 2018, the plaintiffs filed a consolidated complaint. After the parties reached an agreement regarding a stay of the derivative proceeding pending resolution of the tort actions described above and any regulatory proceeding relating to the 2017 Northern California wildfires, on April 24, 2018, the court entered a stipulation and order to stay. The stay is subject to certain conditions regarding the plaintiffs' access to discovery in other actions. On January 28, 2019, the plaintiffs filed a request to lift the stay for the purposes of amending their complaint to add allegations regarding the 2018 Camp fire.

 

On August 3, 2018, a third purported derivative lawsuit, entitled Oklahoma Firefighters Pension and Retirement System v. Chew, et al., was filed in the U.S. District Court for the Northern District of California, naming as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation and the Utility. PG&E Corporation is named as a nominal defendant. The lawsuit alleges claims for breach of fiduciary duties and unjust enrichment as well as a claim under Section 14(a) of the federal Securities Exchange Act of 1934 alleging that PG&E Corporation's and the Utility's 2017 proxy statement contained misrepresentations regarding the companies' risk management and safety programs. On October 15, 2018, PG&E Corporation filed a motion to stay the litigation. The hearing on this motion, previously set for January 31, 2019, was moved by stipulation of the parties and order of the court to March 7, 2019.

 

On October 23, 2018, a fourth purported derivative lawsuit, entitled City of Warren Police and Fire Retirement System v. Chew, et al., was filed in San Francisco County Superior Court, alleging claims for breach of fiduciary duty, corporate waste and unjust enrichment. It names as defendants certain current and former members of the Board of Directors and certain current and former officers of PG&E Corporation, and names PG&E Corporation as a nominal defendant. Plaintiff filed a request with the court seeking the voluntary dismissal of this matter without prejudice on January 18, 2019.

 

On November 21, 2018, a fifth purported derivative lawsuit, entitled Williams v. Earley, Jr., et al., was filed in federal court in San Francisco, alleging claims identical to those alleged in the Oklahoma Firefighters Pension and Retirement System v. Chew, et al. lawsuit listed above against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. This lawsuit includes allegations related to the 2017 Northern California wildfires and the 2018 Camp fire. This action was stayed by stipulation of the parties and order of the court on December 21, 2018, subject to resolution of the pending securities class action.

 

On December 24, 2018, a sixth purported derivative lawsuit, entitled Bowlinger v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants. The court scheduled an initial case management conference for March 21, 2019.

 

On January 25, 2019, a seventh purported derivative lawsuit, entitled Hagberg v. Chew, et al., was filed in San Francisco Superior Court, alleging claims for breach of fiduciary duty, abuse of control, corporate waste, and unjust enrichment in connection with the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation and the Utility as nominal defendants.

 

On January 28, 2019, an eighth purported derivative lawsuit, entitled Blackburn v. Meserve, et al., was filed in federal court alleging claims for breach of fiduciary duty, unjust enrichment, and waste of corporate assets in connection with the 2017 Northern California wildfires and the 2018 Camp fire against certain current and former officers and directors, and naming PG&E Corporation as a nominal defendant.

 

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed notices in each of these proceedings on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 5, 2019, the plaintiff in Bowlinger v. Chew, et al. filed a response to the notice asserting that the automatic stay did not apply to his claims. The court has not yet acted on the plaintiff’s response.

 

Wildfire-Related Securities Class Action Litigation

 

In June 2018, two purported securities class actions were filed in the United States District Court for the Northern District of California, naming PG&E Corporation and certain of its current and former officers as defendants, entitled David C. Weston v. PG&E Corporation, et al. and Jon Paul Moretti v. PG&E Corporation, et al., respectively.  The complaints alleged material misrepresentations and omissions related to, among other things, vegetation management and transmission line safety in various PG&E Corporation public disclosures. The complaints asserted claims under Section 10(b) and Section 20(a) of the federal Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, and sought unspecified monetary relief, interest, attorneys' fees and other costs. Both complaints identified a proposed class period of April 29, 2015 to June 8, 2018. On September 10, 2018, the court consolidated both cases and the litigation is now denominated In Re PG&E Corporation Securities Litigation. The court also appointed the Public Employees Retirement Association of New Mexico as lead plaintiff. The plaintiff filed a consolidated amended complaint on November 9, 2018. After the plaintiff requested leave to amend their complaint to add allegations regarding the 2018 Camp fire, the plaintiff filed a second amended consolidated complaint on December 14, 2018.

 

Due to the commencement of the Chapter 11 Cases, PG&E Corporation and the Utility filed a notice on February 1, 2019, reflecting that the proceedings are automatically stayed pursuant to Section 362(a) of the Bankruptcy Code. On February 15, 2019, PG&E Corporation and the Utility filed a complaint in Bankruptcy Court against the plaintiff seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer defendants.

 

On February 22, 2019, a purported securities class action was filed in the United States District Court for the Northern District of California, entitled York County on behalf of the York County Retirement Fund, et al. v. Rambo, et al. The complaint names as defendants certain current and former officers and directors, as well as the underwriters of 4 public offerings of notes from 2016 to 2018. Neither PG&E Corporation nor the Utility is named as a defendant. The complaint alleges material misrepresentations and omissions in connection with the note offerings related to, among other things, PG&E Corporation’s and the Utility’s vegetation management and wildfire safety measures. The complaint asserts claims under Section 11 and Section 15 of the federal Securities Act of 1933, and seeks unspecified monetary relief, attorneys’ fees and other costs, and injunctive relief. If necessary, PG&E Corporation and the Utility intend to file a complaint in Bankruptcy Court against the plaintiffs seeking preliminary and permanent injunctive relief to extend the stay to the claims alleged against the individual officer and director defendants.

 

Clean-up and Repair Costs

 

The Utility incurred costs of $354 million for clean-up and repair of the Utility’s facilities (including $183 million in capital expenditures) through December 31, 2018, in connection with the 2018 Camp fire. The Utility also incurred costs of $327 million for clean-up and repair of the Utility’s facilities (including $157 million in capital expenditures) through December 31, 2018, in connection with the 2017 Northern California wildfires. The Utility is authorized to track and seek recovery of clean-up and repair costs through CEMA. (CEMA requests are subject to CPUC approval.) The Utility capitalizes and records as regulatory assets costs that are probable of recovery. At December 31, 2018, the CEMA balance related to the 2017 Northern California wildfires was $82 million and is included in long-term regulatory assets on the Consolidated Balance Sheets. Additionally, the capital expenditures for clean-up and repair are included in property, plant and equipment at December 31, 2018.

 

Should PG&E Corporation and the Utility conclude that recovery of any clean-up and repair costs included in the CEMA is no longer probable, PG&E Corporation and the Utility will record a charge in the period such conclusion is reached. Failure to obtain a substantial or full recovery of these costs or any conclusion that such recovery is no longer probable, could have a material effect on PG&E Corporation's and the Utility's financial condition, results of operations, liquidity, and cash flows.

 

2015 Butte Fire

 

In September 2015, a wildfire (the “2015 Butte fire”) ignited and spread in Amador and Calaveras Counties in Northern California. On April 28, 2016, Cal Fire released its report of the investigation of the origin and cause of the 2015 Butte fire. According to Cal Fire’s report, the 2015 Butte fire burned 70,868 acres, resulted in two fatalities, destroyed 549 homes, 368 outbuildings and four commercial properties, and damaged 44 structures.  Cal Fire’s report concluded that the 2015 Butte fire was caused when a gray pine tree contacted the Utility’s electric line, which ignited portions of the tree and determined that the failure by the Utility and/or its vegetation management contractors, ACRT Inc. and Trees, Inc., to identify certain potential hazards during its vegetation management program ultimately led to the failure of the tree.

 

Third-Party Claims

 

On May 23, 2016, individual plaintiffs filed a master complaint against the Utility and its two vegetation management contractors in the Superior Court of California, County of Sacramento.  Subrogation insurers also filed a separate master complaint on the same date.  The California Judicial Council previously had authorized the coordination of all cases in Sacramento County.  As of January 31, 2019, 95 known complaints have been filed against the Utility and its two vegetation management contractors in the Superior Court of California in the Counties of Calaveras, San Francisco, Sacramento, and Amador.  The complaints involve approximately 3,900 individual plaintiffs representing approximately 2,000 households and their insurance companies.  These complaints are part of, or were in the process of being added to, the coordinated proceeding.  Plaintiffs seek to recover damages and other costs, principally based on the doctrine of inverse condemnation and negligence theory of liability.  Plaintiffs also seek punitive damages.  Several plaintiffs dismissed the Utility's two vegetation management contractors from their complaints. The Utility does not expect the number of claimants to increase significantly in the future, because the statute of limitations for property damage and personal injury in connection with the 2015 Butte fire has expired. Further, due to the commencement of the Chapter 11 Cases, these plaintiffs have been stayed from continuing to prosecute pending litigation and from commencing new lawsuits against PG&E Corporation or the Utility on account of pre-petition obligations. On January 30, 2019, the Court in the coordinated proceeding issued an order staying the action.

 

On April 28, 2017, the Utility moved for summary adjudication on plaintiffs’ claims for punitive damages.  The court denied the Utility’s motion and the Utility filed a writ with the Court of Appeal of the State of California, Third Appellate District. The writ was granted on July 2, 2018, directing the trial court to enter summary adjudication in favor of the Utility and to deny plaintiffs' claim for punitive damages under California Civil Code Section 3294. Plaintiffs sought rehearing and asked the California Supreme Court to review the Court of Appeal's decision. Both requests were denied. Neither the trial nor appellate courts originally addressed whether plaintiffs can seek punitive damages at trial under Public Utilities Code Section 2106. However, the trial court, in November 2018, denied a motion filed by the Utility that would have confirmed that punitive damages under Public Utilities Code Section 2106 are unavailable. The Utility believes a loss related to punitive damages is unlikely, but possible.

 

On June 22, 2017, the Superior Court of California, County of Sacramento ruled on a motion of several plaintiffs and found that the doctrine of inverse condemnation applies to the Utility with respect to the 2015 Butte fire. The court held, among other things, that the Utility had failed to put forth any evidence to support its contention that the CPUC would not allow the Utility to pass on its inverse condemnation liability through rate increases. While the ruling is binding only between the Utility and the plaintiffs in the coordination proceeding at the time of the ruling, others could make similar claims. On January 4, 2018, the Utility filed with the court a renewed motion for a legal determination of inverse condemnation liability, citing the November 30, 2017 CPUC decision denying the San Diego Gas & Electric Company application to recover wildfire costs in excess of insurance, and the CPUC declaration that it will not automatically allow utilities to spread inverse condemnation losses through rate increases.

 

On May 1, 2018, the Superior Court of California, County of Sacramento issued its ruling on the Utility’s renewed motion in which the court affirmed, with minor changes, its tentative ruling dated April 25, 2018. The court determined that it is bound by earlier holdings of two appellate courts decisions, Barham and Pacific Bell. Further, the court stated that the Utility's constitutional arguments should be made to the appellate courts and suggested that, to the extent the Utility raises the public policy implications of the November 30, 2017 CPUC decision in the San Diego Gas & Electric Company cost recovery proceeding, these arguments should be addressed to the Legislature or CPUC. The Utility filed a writ with the Court of Appeal seeking immediate review of the court's decision. On June 18, 2018, after the writ was summarily denied, the Utility filed a Petition for Review with the California Supreme Court, which also was denied. On September 6, 2018, the court set a trial for some individual plaintiffs to begin on April 1, 2019. The Utility reached agreement with two plaintiffs in the litigation to stipulate to judgment against the Utility on inverse condemnation grounds. The court granted the Utility's stipulated judgment motion on November 29, 2018 and the Utility filed its appeal on December 11, 2018. As a result of the filing of the Chapter 11 Cases, these lawsuits, including the trial and the appeal from the stipulated judgment, are stayed.

 

In addition to the coordinated plaintiffs, Cal Fire, the California Office of Emergency Services (the “OES”), the County of Calaveras, and five smaller public entities (three fire districts, one water district and the California Department of Veterans Affairs) have brought suit or indicated that they intend to do so. The five smaller public entities filed their complaints in August 2018 and September 2018. They have been added to the coordinated proceedings. The Utility has settled the claims of the three fire protection districts.

 

On April 13, 2017, Cal Fire filed a complaint with the Superior Court of California, County of Calaveras, seeking to recover over $87 million for its costs incurred on the theory that the Utility and its vegetation management contractors were negligent, or violated the law, among other claims.  On July 31, 2017, Cal Fire dismissed its complaint against Trees, Inc., one of the Utility's vegetation contractors. Cal Fire had requested that a trial of its claims be set in 2019, following any trial of the claims of the individual plaintiffs. On October 19, 2018, the Utility filed a motion for summary judgment arguing that Cal Fire cannot recover any fire suppression costs under the Third District Court of Appeal's decision in Dep't of Forestry & Fire Prot. v. Howell (2017) 18 Cal. App. 5th 154. The hearing on that motion was set for January 31, 2019, but the hearing and Cal Fire’s case against the Utility are now stayed. Prior to the stay, the Utility and Cal Fire were also engaged in a mediation process.

 

Also, on February 20, 2018, the County of Calaveras filed suit against the Utility and the Utility’s vegetation management contractors to recover damages and other costs, based on the doctrine of inverse condemnation and negligence theory of liability. The County also sought punitive damages. On March 2, 2018, the County served a mediation demand seeking in excess of $167 million, having previously indicated that it intended to bring an approximately $85 million claim against the Utility. This claim included costs that the County of Calaveras allegedly incurred or expected to incur for infrastructure damage, erosion control, and other costs. The Utility and the County of Calaveras settled the County's claims in November 2018 for $25.4 million.

 

Further, in May 2017, the OES indicated that it intended to bring a claim against the Utility that it estimated to be approximately $190 million.  This claim would include costs incurred by the OES for tree and debris removal, infrastructure damage, erosion control, and other claims related to the 2015 Butte fire. The Utility has not received any information or documentation from OES since its May 2017 statement. In June 2017, the Utility entered into an agreement with the OES that extends their deadline to file a claim to December 2020.

 

PG&E Corporation's and the Utility's obligations with respect to such outstanding claims are expected to be determined through the Chapter 11 process.

 

Estimated Losses from Third-Party Claims

 

In connection with the 2015 Butte fire, the Utility may be liable for property damages, business interruption, interest, and attorneys’ fees without having been found negligent, through the doctrine of inverse condemnation.

 

In addition, the Utility may be liable for fire suppression costs, personal injury damages, and other damages if the Utility is found to have been negligent.  While the Utility believes it was not negligent, there can be no assurance that a court would agree with the Utility.

 

The Utility’s assessment of the estimated loss related to the 2015 Butte fire is based on assumptions about the number, size, and type of structures damaged or destroyed, the contents of such structures, the number and types of trees damaged or destroyed, as well as assumptions about personal injury damages, attorneys’ fees, fire suppression costs, and certain other damages.

 

The Utility has determined that it is probable that it will incur a loss of $1.1 billion in connection with the 2015 Butte fire. While this amount includes the Utility's assumptions about fire suppression costs (including its assessment of the Cal Fire loss), it does not include any portion of the estimated claim from the OES. The Utility still does not have sufficient information to reasonably estimate any liability it may have for that additional claim.

 

The process for estimating costs associated with claims relating to the 2015 Butte fire requires management to exercise significant judgment based on a number of assumptions and subjective factors.  As more information becomes known, management estimates and assumptions regarding the financial impact of the 2015 Butte fire may result in material increases to the loss accrued.

 

The following table presents changes in the third-party claims liability since December 31, 2015.  The balance for the third-party claims liability is included in Wildfire-related claims in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Loss Accrual (in millions)

 

Balance at December 31, 2015

$

 

Accrued losses

750

 

Payments (1)

(60

)

Balance at December 31, 2016

690

 

Accrued losses

350

 

Payments (1)

(479

)

Balance at December 31, 2017

561

 

Accrued losses

 

Payments (1)

(335

)

Balance at December 31, 2018

$

226

 

 

 

(1) As of December 31, 2018, the Utility has paid $874 million of the $904 million in settlements to date in connection with the 2015 Butte fire.

 

If the Utility records losses in connection with claims relating to the 2015 Butte fire that materially exceed the amount the Utility accrued for these liabilities, PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows could be materially affected in the reporting periods during which additional charges are recorded.

 

Loss Recoveries

 

The Utility has liability insurance from various insurers, that provides coverage for third-party liability attributable to the 2015 Butte fire in an aggregate amount of $922 million.  The Utility records insurance recoveries when it is deemed probable that a recovery will occur and the Utility can reasonably estimate the amount or its range.  Through December 31, 2018, the Utility recorded $922 million for probable insurance recoveries in connection with losses related to the 2015 Butte fire.  While the Utility plans to seek recovery of all insured losses, it is unable to predict the ultimate amount and timing of such insurance recoveries.  In addition, the Utility has received $60 million in cumulative reimbursements from the insurance policies of its vegetation management contractors (excluded from the table below), including $7 million received in the year ended December 31, 2018. Recoveries of additional amounts under the insurance policies of the Utility’s vegetation management contractors, including policies where the Utility is listed as an additional insured, are uncertain.

 

The following table presents changes in the insurance receivable since December 31, 2015.  The balance for the insurance receivable is included in Other accounts receivable in PG&E Corporation’s and the Utility’s Consolidated Balance Sheets:

Insurance Receivable (in millions)

 

Balance at December 31, 2015

$

 

Accrued insurance recoveries

625

 

Reimbursements

(50

)

Balance at December 31, 2016

575

 

Accrued insurance recoveries

297

 

Reimbursements

(276

)

Balance at December 31, 2017

596

 

Accrued insurance recoveries

 

Reimbursements

(511

)

Balance at December 31, 2018

$

85

 

 

In January and February 2019, the Utility received an additional $25 million in insurance reimbursements.

 

NOTE 14: OTHER CONTINGENCIES AND COMMITMENTS

 

PG&E Corporation and the Utility have significant contingencies arising from their operations, including contingencies related to enforcement and litigation matters and environmental remediation.  A provision for a loss contingency is recorded when it is both probable that a loss has been incurred and the amount of the loss can be reasonably estimated.  PG&E Corporation and the Utility evaluate the range of reasonably estimated losses and record a provision based on the lower end of the range, unless an amount within the range is a better estimate than any other amount.  The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events.  Loss contingencies are reviewed quarterly and estimates are adjusted to reflect the impact of all known information, such as negotiations, discovery, settlements and payments, rulings, advice of legal counsel, and other information and events pertaining to a particular matter.  PG&E Corporation’s and the Utility’s policy is to exclude anticipated legal costs from the provision for loss and expense these costs as incurred. The Utility also has substantial financial commitments in connection with agreements entered into to support its operating activities.  See “Purchase Commitments” below.  PG&E Corporation has financial commitments described in “Other Commitments” below.  PG&E Corporation’s and the Utility’s financial condition, results of operations, liquidity, and cash flows may be materially affected by the outcome of the following matters.

 

Enforcement Matters

 

In 2014, both the U.S. Attorney's Office in San Francisco and the California Attorney General's office opened investigations into matters related to allegedly improper communication between the Utility and CPUC personnel.  The Utility has cooperated with those investigations.  It is uncertain whether any charges will be brought against the Utility. Such proceedings are not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

 

CPUC and FERC Matters

 

Order Instituting an Investigation and Order to Show Cause into the Utility's Locate and Mark practices

 

On December 14, 2018, the CPUC issued an OII and order to show cause (the "OII") to assess the Utility's practices and procedures related to the locating and marking of natural gas facilities. The OII directs the Utility to show cause as to why the Commission should not find violations in this matter, and why the Commission should not impose penalties, and/or any other forms of relief, if any violations are found. The Utility also is directed in the OII to provide a report on specific matters, including that it is conducting locate and mark programs in a safe manner.

 

The OII cites a report by the SED dated December 6, 2018, which alleges that the Utility violated the law pertaining to the locating and marking of its gas facilities and falsified records related to its locate and mark activities between 2012 and 2017. As described in the OII, the SED cites reports issued in this matter by two consultants retained by the Utility, that (i) included certain facts and conclusions about the extent of inaccuracies in the Utility’s late tickets and the reasons for the inaccuracies, and (ii) provided the Utility’s late tickets counts, and identification of associated dig-ins. As a result, the OII will determine whether the Utility violated any provision of the Public Utilities Code, general orders, federal law adopted by California, other rules, or requirements, and/or other state or federal law, by its locate and mark policies, practices, and related issues, and the extent to which the Utility’s practices with regard to locate and mark may have diminished system safety.

 

The CPUC indicates that it has not concluded that the Utility has violated the law in any instance pertaining to late tickets, locating and marking, or any matter related to either, or to any other matter raised in this OII. However, if violations are found, the CPUC will consider what monetary fines and other remedies are appropriate, will review the duration of violations and, if supported by the evidence, it will consider ordering daily fines.

 

On January 14, 2019, the Utility submitted responses to preliminary questions raised in the OII and separately filed an affidavit regarding the safety of the locate and mark program. On March 14, 2019, as directed by the CPUC, the Utility expects to submit a report that addresses the SED report and respond to the order to show cause. A schedule for future proceedings is expected to be established at an April 5, 2019 pre-hearing conference.

 

PG&E Corporation and the Utility believe it is probable that the CPUC will impose penalties, including fines or other remedies, on the Utility. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the CPUC's wide discretion and the number of factors that can be considered in determining penalties. The Utility is unable to predict the timing and outcome of this proceeding.

 

Such proceedings are likely not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

 

Order Instituting an Investigation into Compliance with Ex Parte Communication Rules

 

During 2014 and 2015, the Utility filed several reports to notify the CPUC of communications that the Utility believes may have constituted or described ex parte communications that either should not have occurred or that should have been timely reported to the CPUC.  Ex parte communications include communications between a decision maker and interested persons concerning substantive issues in certain formal proceedings.  Certain communications are prohibited and others are permissible with proper noticing and reporting.

 

On November 23, 2015, the CPUC issued an OII into whether the Utility should be sanctioned for violating rules pertaining to ex parte communications and Rule 1.1 of the CPUC’s Rules of Practice and Procedure governing the conduct of those appearing before the CPUC.  The OII cites some of the communications the Utility reported to the CPUC.  The OII also cites the ex parte violations alleged in the City of San Bruno’s July 2014 motion, which it filed in CPUC investigations related to the Utility’s natural gas transmission pipeline operations and practices.

 

On April 26, 2018, the CPUC approved the revised proposed decision issued on April 3, 2018, adopting the settlement agreement jointly submitted to the CPUC on March 28, 2017, as modified (the "settlement agreement") by the Utility, the Cities of San Bruno and San Carlos, Cal PA, the SED, and TURN.

 

The decision results in a total penalty of $97.5 million comprised of: (1) a $12 million payment to the California General Fund,

(2) forgoing collection of $63.5 million of GT&S revenue requirements for the years 2018 ($31.75 million) and 2019 ($31.75 million), (3) a $10 million one-time revenue requirement adjustment to be amortized in equivalent annual amounts over the Utility’s next GRC cycle (i.e., the 2020 GRC), and (4) compensation payments to the Cities of San Bruno and San Carlos in a total amount of $12 million ($6 million to each city). In addition, the settlement agreement provides for certain non-financial remedies, including enhanced noticing obligations between the Utility and CPUC decision-makers, as well as certification of employee training on the CPUC ex parte communication rules. Under the terms of the settlement agreement, customers will bear no costs associated with the financial remedies set forth above.

 

As a result of the CPUC's April 26, 2018 decision, on May 17, 2018, the Utility made a $12 million payment to the California General Fund and $6 million payments to each of the Cities of San Bruno and San Carlos. At December 31, 2018, PG&E Corporation’s and the Utility’s Consolidated Balance Sheets include a $32 million accrual for a portion of the 2018 GT&S revenue requirement reduction. In accordance with accounting rules, adjustments related to revenue requirements are recorded in the periods in which they are incurred.

 

The CPUC also ordered a second phase in this proceeding to determine if any of the additional communications that the Utility reported to the CPUC on September 21, 2017, violate the CPUC ex parte rules. On May 22, 2018, the assigned ALJ issued a ruling requiring the parties to meet and confer to determine if an agreement can be reached on the issues identified by the ALJ. On September 17, 2018, the parties submitted a joint status report indicating a settlement in principle could not be reached. The ALJ will hold a prehearing conference with the parties to determine if evidentiary hearings are required. The Utility is unable to predict the timing and outcome of the second phase in this proceeding.

 

Such proceedings are likely not subject to the automatic stay imposed as a result of the commencement of the Chapter 11 Cases; however, collection efforts in connection with fines or penalties arising out of such proceedings are stayed.

 

Transmission Owner Rate Case Revenue Subject to Refund

 

The FERC determines the amount of authorized revenue requirements, including the rate of return on electric transmission assets, that the Utility may collect in rates in the TO rate case. The FERC typically authorizes the Utility to charge new rates based on the requested revenue requirement, subject to refund, before the FERC has issued a final decision. The Utility bills and records revenue based on the amounts requested in its rate case filing and records a reserve for its estimate of the amounts that are probable of refund. Rates subject to refund went into effect on March 1, 2017, and March 1, 2018, for TO18 and TO19, respectively. Rates subject to refund for TO20 will go into effect on May 1, 2019.

 

On October 1, 2018, the ALJ issued an initial decision in the TO18 rate case and the Utility filed initial briefs on October 31, 2018, in response to the ALJ's recommendations. The Utility expects the FERC to issue a decision in the TO18 rate case by mid-2019, however, that decision will likely be the subject of requests for rehearing and appeal. The Utility is unable to predict the timing of when a final decision will be issued. On September 21, 2018, the Utility filed an all-party settlement with FERC in connection with TO19. As part of the settlement, the TO19 revenue requirement will be set at 98.85% of the revenue requirement for TO18 that will be determined in the TO18 final decision. The Utility is unable to predict the timing or outcome of FERC’s decisions in these proceedings.

 

Natural Gas Transmission Pipeline Rights-of-Way

 

In 2012, the Utility notified the CPUC and the SED that the Utility planned to complete a system-wide survey of its transmission pipelines in an effort to address a self-reported violation whereby the Utility did not properly identify encroachments (such as building structures and vegetation overgrowth) on the Utility’s pipeline rights-of-way. The Utility also submitted a proposed compliance plan that set forth the scope and timing of remedial work to remove identified encroachments over a multi-year period and to pay penalties if the proposed milestones were not met. In March 2014, the Utility informed the SED that the survey had been completed and that remediation work, including removal of the encroachments, was expected to continue for several years. The SED has not addressed the Utility’s proposed compliance plan, and it is reasonably possible that the SED will impose fines on the Utility in the future based on the Utility’s failure to continuously survey its system and remove encroachments. The Utility is unable to reasonably estimate the amount or range of future charges that could be incurred given the SED’s wide discretion and the number of factors that can be considered in determining penalties.

 

Other Matters

 

PG&E Corporation and the Utility are subject to various claims, lawsuits and regulatory proceedings that separately are not considered material.  Accruals for contingencies related to such matters (excluding amounts related to the contingencies discussed in Note 13 and above under “Enforcement and Litigation Matters”) totaled $98 million at December 31, 2018 and $86 million at December 31, 2017.  These amounts are included in Other current liabilities in the Consolidated Balance Sheets.  PG&E Corporation and the Utility do not believe it is reasonably possible that the resolution of these matters will have a material effect on their financial condition, results of operations, liquidity, and cash flows.

 

2015 GT&S Rate Case Disallowance of Capital Expenditures

 

On June 23, 2016, the CPUC approved a final phase one decision in the Utility’s 2015 GT&S rate case.  The phase one decision excluded from rate base $696 million of capital spending in 2011 through 2014 in excess of the amount adopted in the prior GT&S rate case. The decision permanently disallowed $120 million of that amount and ordered that the remaining $576 million be subject to an audit overseen by the CPUC staff, with the possibility that the Utility may seek recovery in a future proceeding. The decision also established various cost caps that will increase the risk of overspend over the current rate case cycle including new one-way balancing accounts. As a result, in 2016, the Utility incurred charges of $219 million for capital expenditures that the Utility believes are probable of disallowance based on the decision. This included $134 million for 2011 through 2014 capital expenditures in excess of adopted amounts and $44 million for the Utility’s estimate of 2015 through 2018 capital expenditures that are probable of exceeding authorized amounts. The Utility would be required to take a charge in the future if the CPUC's audit of 2011 through 2014 capital spending resulted in additional permanent disallowance. The audit is still in process.

 

Environmental Remediation Contingencies

 

Given the complexities of the legal and regulatory environment and the inherent uncertainties involved in the early stages of a remediation project, the process for estimating remediation liabilities requires significant judgment. The Utility records an environmental remediation liability when the site assessments indicate that remediation is probable and the Utility can reasonably estimate the loss or a range of probable amounts. The Utility records an environmental remediation liability based on the lower end of the range of estimated probable costs, unless an amount within the range is a better estimate than any other amount. Key factors that inform the development of estimated costs include site feasibility studies and investigations, applicable remediation actions, operations and maintenance activities, post-remediation monitoring, and the cost of technologies that are expected to be approved to remediate the site. Amounts recorded are not discounted to their present value. The Utility’s environmental remediation liability is primarily included in non-current liabilities on the Consolidated Balance Sheets and is comprised of the following:

 

Balance at

(in millions)

December 31,
2018

 

December 31,
2017

Topock natural gas compressor station

$

369

 

 

$

334

 

Hinkley natural gas compressor station

146

 

 

147

 

Former manufactured gas plant sites owned by the Utility or third parties (1)

520

 

 

320

 

Utility-owned generation facilities (other than fossil fuel-fired),

  other facilities, and third-party disposal sites (2)

111

 

 

115

 

Fossil fuel-fired generation facilities and sites (3)

137

 

 

123

 

Total environmental remediation liability

$

1,283

 

 

$

1,039

 

 

 

 

 

(1) Primarily driven by the following sites: Vallejo, San Francisco East Harbor, Napa, and San Francisco North Beach.

(2) Primarily driven by Geothermal landfill and Shell Pond site.

(3) Primarily driven by the San Francisco Potrero Power Plant.

 

The Utility’s gas compressor stations, former manufactured gas plant sites, power plant sites, gas gathering sites, and sites used by the Utility for the storage, recycling, and disposal of potentially hazardous substances are subject to requirements issued by the EPA under the Federal Resource Conservation and Recovery Act in addition to other state hazardous waste laws.  The Utility has a comprehensive program in place designed to comply with federal, state, and local laws and regulations related to hazardous materials, waste, remediation activities, and other environmental requirements.  The Utility assesses and monitors the environmental requirements on an ongoing basis, and implements changes to its program as deemed appropriate. The Utility’s remediation activities are overseen by the DTSC, several California regional water quality control boards, and various other federal, state, and local agencies.

 

The Utility’s environmental remediation liability at December 31, 2018, reflects its best estimate of probable future costs for remediation based on the current assessment data and regulatory obligations. Future costs will depend on many factors, including the extent of work necessary to implement final remediation plans and the Utility's time frame for remediation.  The Utility may incur actual costs in the future that are materially different than this estimate and such costs could have a material effect on results of operations, financial condition, liquidity, and cash flows during the period in which they are recorded. At December 31, 2018, the Utility expected to recover $930 million of its environmental remediation liability for certain sites through various ratemaking mechanisms authorized by the CPUC.

 

Natural Gas Compressor Station Sites

 

The Utility is legally responsible for remediating groundwater contamination caused by hexavalent chromium used in the past at the Utility’s natural gas compressor stations. The Utility is also required to take measures to abate the effects of the contamination on the environment.

 

Topock Site

 

The Utility’s remediation and abatement efforts at the Topock site are subject to the regulatory authority of the California DTSC and the U.S. Department of the Interior. On April 24, 2018, the DTSC authorized the Utility to build an in-situ groundwater treatment system to convert hexavalent chromium into a non-toxic and non-soluble form of chromium. Construction activities began in October 2018 and will continue for several years. The Utility’s undiscounted future costs associated with the Topock site may increase by as much as $303 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Topock site are expected to be recovered primarily through the HSM, where 90% of the costs are recovered in rates.

 

Hinkley Site

 

The Utility has been implementing remediation measures at the Hinkley site to reduce the mass of the chromium plume in groundwater and to monitor and control movement of the plume. The Utility’s remediation and abatement efforts at the Hinkley site are subject to the regulatory authority of the California Regional Water Quality Control Board, Lahontan Region. In November 2015, the California Regional Water Quality Control Board, Lahontan Region adopted a clean-up and abatement order directing the Utility to contain and remediate the underground plume of hexavalent chromium and the potential environmental impacts. The final order states that the Utility must continue and improve its remediation efforts, define the boundaries of the chromium plume, and take other action. Additionally, the final order sets plume capture requirements, requires a monitoring and reporting program, and includes deadlines for the Utility to meet interim cleanup targets. The United States Geological Survey team is currently conducting a background study on the site to better define the chromium plume boundaries. The background study is expected to be finalized in 2019. The Utility’s undiscounted future costs associated with the Hinkley site may increase by as much as $141 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the Hinkley site will not be recovered through rates.

 

Former Manufactured Gas Plants

 

Former MGPs used coal and oil to produce gas for use by the Utility’s customers before natural gas became available. The by-products and residues of this process were often disposed of at the MGPs themselves. The Utility has undertaken a program to manage the residues left behind as a result of the manufacturing process; many of the sites in the program have been addressed. The Utility’s undiscounted future costs associated with MGP sites may increase by as much as $518 million if the extent of contamination or necessary remediation is greater than anticipated. The costs associated with environmental remediation at the MGP sites are recovered through the HSM, where 90% of the costs are recovered in rates.

 

Utility-Owned Generation Facilities and Third-Party Disposal Sites

 

Utility-owned generation facilities and third-party disposal sites often involve long-term remediation. The Utility’s undiscounted future costs associated with Utility-owned generation facilities and third-party disposal sites may increase by as much as $135 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the Utility-owned generation facilities and third-party disposal sites are recovered through the HSM, where 90% of the costs are recovered in rates.

 

Fossil Fuel-Fired Generation Sites

 

In 1998, the Utility divested its generation power plant business as part of generation deregulation. Although the Utility sold its fossil-fueled power plants, the Utility retained the environmental remediation liability associated with each site. The Utility’s undiscounted future costs associated with fossil fuel-fired generation sites may increase by as much as $105 million if the extent of contamination or necessary remediation is greater than anticipated. The environmental remediation costs associated with the fossil fuel-fired sites will not be recovered through rates.

 

Insurance

 

Wildfire Insurance

 

In 2018, PG&E Corporation and the Utility renewed their liability insurance coverage for wildfire events in an aggregate amount of approximately $1.4 billion for the period from August 1, 2018 through July 31, 2019, comprised of $700 million for general liability (subject to an initial self-insured retention of $10 million per occurrence), and $700 million for property damages only, which property damage coverage includes an aggregate amount of approximately $200 million through the reinsurance market where a catastrophe bond was utilized. Various coverage limitations applicable to different insurance layers could result in substantial uninsured costs in the future depending on the amount and type of damages.

 

PG&E Corporation’s and the Utility’s cost of obtaining wildfire insurance coverage has increased to $360 million, compared to the adopted approximately $50 million that the Utility is currently recovering through rates through December 31, 2019. The Utility intends to seek recovery for the full amount of premium costs paid in excess of the amount the Utility currently is recovering from customers through the end of the current GRC period, which ends on December 31, 2019.

 

Nuclear Insurance

 

The Utility is a member of NEIL, which is a mutual insurer owned by utilities with nuclear facilities.  NEIL provides insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear event were to occur at the Utility’s two nuclear generating units at Diablo Canyon and the retired Humboldt Bay Unit 3. NEIL provides property damage and business interruption coverage of up to $3.2 billion per nuclear incident and $2.6 billion per non-nuclear incident for Diablo Canyon.  Humboldt Bay Unit 3 has up to $131 million of coverage for nuclear and non-nuclear property damages.

 

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants.  Certain acts of terrorism may be “certified” by the Secretary of the Treasury.  If damages are caused by certified acts of terrorism, NEIL can obtain reimbursement from the federal government up to a shared limit of $3.2 billion for each insured loss for NEIL members.  In contrast, for acts of terrorism not deemed "certified" by the Secretary of the Treasury, NEIL treats all non-certified terrorist acts occurring within a 12-month period against one or more commercial nuclear power plants insured by NEIL as one event and the owners of the affected plants would share a $3.2 billion policy limit amount.

 

In addition to the nuclear insurance the Utility maintains through the NEIL, the Utility also is a member of the EMANI, which provides excess insurance coverage for property damages and business interruption losses incurred by the Utility if a nuclear or non-nuclear event were to occur at Diablo Canyon. EMANI provides $200 million for any one accident and in the annual aggregate excess of the combined amount recoverable under the Utility’s NEIL policies

 

If NEIL losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment.  If NEIL were to exercise this assessment, as of December 31, 2018, the current maximum aggregate annual retrospective premium obligation for the Utility would be approximately $47 million.  If EMANI losses in any policy year exceed accumulated funds, the Utility could be subject to a retrospective assessment of approximately $3 million, as of December 31, 2018.

 

Under the Price-Anderson Act, public liability claims that arise from nuclear incidents that occur at Diablo Canyon, and that occur during the transportation of material to and from Diablo Canyon are limited to $14.1 billion.  The Utility purchased the maximum available public liability insurance of $450 million for Diablo Canyon.  The balance of the $14.1 billion of liability protection is provided under a loss-sharing program among utilities owning nuclear reactors.  The Utility may be assessed up to $275 million per nuclear incident under this program, with payments in each year limited to a maximum of $41 million per incident.  Both the maximum assessment and the maximum yearly assessment are adjusted for inflation at least every five years.

 

The Price-Anderson Act does not apply to claims that arise from nuclear incidents that occur during shipping of nuclear material from the nuclear fuel enricher to a fuel fabricator or that occur at the fuel fabricator’s facility.  The Utility has a separate policy that provides coverage for claims arising from some of these incidents up to a maximum of $450 million per incident.  In addition, the Utility has $53 million of liability insurance for Humboldt Bay Unit 3 and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents for Humboldt Bay Unit 3, covering liabilities in excess of the $53 million in liability insurance.

 

Resolution of Remaining 2001 Chapter 11 Disputed Claims

 

Various electricity suppliers filed claims in the Utility’s 2001 prior proceeding filed under Chapter 11 of the U.S. Bankruptcy Code seeking payment for energy supplied to the Utility’s customers between May 2000 and June 2001.  While the FERC and judicial proceedings are pending, the Utility pursued settlements with electricity suppliers and entered into a number of settlement agreements with various electricity suppliers to resolve some of these disputed claims and to resolve the Utility’s refund claims against these electricity suppliers. Under these settlement agreements, amounts payable by the parties, in some instances, would be subject to adjustment based on the outcome of the various refund offset and interest issues being considered by the FERC. Generally, any net refunds, claim offsets, or other credits that the Utility receives from electricity suppliers either through settlement or through the conclusion of the various FERC and judicial proceedings are refunded to customers through rates in future periods.

 

At December 31, 2018 and December 31, 2017, respectively, the Consolidated Balance Sheets reflected $220 million and $243 million in net claims within Disputed claims and customer refunds related to the 2001 Chapter 11 proceeding.  The Utility's obligations with respect to such claims (all of which arose prior to the initiation of the Utility's pending Chapter 11 Case on January 29, 2019), including pursuant to any prior settlements relating thereto, are expected to be determined through the proceedings of the Chapter 11 Cases.

 

Purchase Commitments

 

The following table shows the undiscounted future expected obligations under power purchase agreements that have been approved by the CPUC and have met specified construction milestones as well as undiscounted future expected payment obligations for natural gas supplies, natural gas transportation, natural gas storage, and nuclear fuel as of December 31, 2018:

 

Power Purchase Agreements

 

 

 

 

 

 

(in millions)

Renewable

Energy

 

Conventional

Energy

 

Other

 

Natural

Gas

 

Nuclear

Fuel

 

Total

2019

$

2,221

 

 

$

642

 

 

$

108

 

 

$

412

 

 

$

108

 

 

$

3,491

 

2020

2,183

 

 

639

 

 

83

 

 

153

 

 

151

 

 

3,209

 

2021

2,174

 

 

582

 

 

65

 

 

93

 

 

64

 

 

2,978

 

2022

1,984

 

 

511

 

 

61

 

 

93

 

 

54

 

 

2,703

 

2023

1,914

 

 

223

 

 

61

 

 

93

 

 

49

 

 

2,340

 

Thereafter

24,217

 

 

435

 

 

162

 

 

264

 

 

47

 

 

25,125

 

Total purchase commitments

$

34,693

 

 

$

3,032

 

 

$

540

 

 

$

1,108

 

 

$

473

 

 

$

39,846

 

 

Subject to certain exceptions, under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assign or reject certain executory contracts and unexpired leases, subject to the approval of the Bankruptcy Court and satisfaction of certain other conditions. (For more information see "Chapter 11 Proceedings" in Note 15 below.)

 

Third-Party Power Purchase Agreements

 

In the ordinary course of business, the Utility enters into various agreements, including renewable energy agreements, QF agreements, and other power purchase agreements to purchase power and electric capacity.  The price of purchased power may be fixed or variable.  Variable pricing is generally based on the current market price of either natural gas or electricity at the date of delivery.

 

Renewable Energy Power Purchase Agreements.  In order to comply with California’s RPS requirements, the Utility is required to deliver renewable energy to its customers at a gradually increasing rate.  The Utility has entered into various agreements to purchase renewable energy to help meet California’s requirement. The Utility’s obligations under a significant portion of these agreements are contingent on the third party’s construction of new generation facilities, which are expected to grow.  As of December 31, 2018, renewable energy contracts expire at various dates between 2019 and 2043.

 

Conventional Energy Power Purchase Agreements.  The Utility has entered into many power purchase agreements for conventional generation resources, which include tolling agreements and resource adequacy agreements.  The Utility’s obligation under a portion of these agreements is contingent on the third parties’ development of new generation facilities to provide capacity and energy products to the Utility. As of December 31, 2018, these power purchase agreements expire at various dates between 2019 and 2033.

 

Other Power Purchase Agreements.  The Utility has entered into agreements to purchase energy and capacity with independent power producers that own generation facilities that meet the definition of a QF under federal law.  Two of these agreements are treated as capital leases.  At December 31, 2018 and 2017, net capital leases reflected in property, plant, and equipment on the Consolidated Balance Sheets were $11 million and $18 million including accumulated amortization of $8 million and $143 million, respectively.  The present value of the future minimum lease payments due under these agreements included $2 million and $11 million in Current Liabilities and $9 million and $7 million in Noncurrent Liabilities on the Consolidated Balance Sheet, respectively. As of December 31, 2018, QF contracts in operation expire at various dates between 2019 and 2049.  In addition, the Utility has agreements with various irrigation districts and water agencies to purchase hydroelectric power.

 

The costs incurred for all power purchases and electric capacity amounted to $3.1 billion in 2018, $3.3 billion in 2017, and $3.5 billion in 2016.

 

Natural Gas Supply, Transportation, and Storage Commitments

 

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers and to fuel its owned-generation facilities.  The Utility also contracts for natural gas transportation from the points at which the Utility takes delivery (typically in Canada, the US Rocky Mountain supply area, and the southwestern United States) to the points at which the Utility’s natural gas transportation system begins.  These agreements expire at various dates between 2019 and 2026.  In addition, the Utility has contracted for natural gas storage services in northern California to more reliably meet customers’ loads.

 

Costs incurred for natural gas purchases, natural gas transportation services, and natural gas storage, which include contracts with terms of less than 1 year, amounted to $0.6 billion in 2018, $0.9 billion in 2017, and $0.7 billion in 2016.

 

Nuclear Fuel Agreements

 

The Utility has entered into several purchase agreements for nuclear fuel.  These agreements expire at various dates between 2019 and 2024 and are intended to ensure long-term nuclear fuel supply.  The Utility relies on a number of international producers of nuclear fuel in order to diversify its sources and provide security of supply.  Pricing terms are also diversified, ranging from market-based prices to base prices that are escalated using published indices.

 

Payments for nuclear fuel amounted to $73 million in 2018, $83 million in 2017, and $100 million in 2016.

 

Other Commitments

 

PG&E Corporation and the Utility have other commitments related to operating leases (primarily office facilities and land), which expire at various dates between 2019 and 2052.  At December 31, 2018, the future minimum payments related to these commitments were as follows:

(in millions)

Operating Leases

2019

$

44

 

2020

41

 

2021

36

 

2022

28

 

2023

19

 

Thereafter

121

 

Total minimum lease payments

$

289

 

 

Payments for other commitments related to operating leases amounted to $43 million in 2018, $45 million in 2017, and $43 million in 2016.  Certain leases on office facilities contain escalation clauses requiring annual increases in rent.  The rentals payable under these leases may increase by a fixed amount each year, a percentage of increase over base year, or the consumer price index.  Most leases contain extension operations ranging between one and five years.


NOTE 15: SUBSEQUENT EVENTS

 

Chapter 11 Proceedings

 

On the Petition Date, PG&E Corporation and the Utility filed voluntary petitions for relief under Chapter 11 in the Bankruptcy Court. PG&E Corporation's and the Utility’s Chapter 11 Cases are being jointly administered under the caption In re: PG&E Corporation and Pacific Gas and Electric Company, Case No. 19-30088 (DM).

 

PG&E Corporation and the Utility continue to operate their businesses as debtors in possession under the jurisdiction of the Bankruptcy Court and in accordance with applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. As debtors in possession, PG&E Corporation and the Utility are authorized to continue to operate as ongoing businesses, and may pay all debts and honor all obligations arising in the ordinary course of their businesses after the Petition Date. However, PG&E Corporation and the Utility may not pay third-party claims or creditors on account of obligations arising before the Petition Date or engage in transactions outside the ordinary course of business without approval of the Bankruptcy Court.

 

Under the Bankruptcy Code, third-party actions to collect pre-petition indebtedness owed by PG&E Corporation or the Utility, as well as most litigation pending against PG&E Corporation and the Utility (including the third-party matters described in Note 13 above), are subject to an automatic stay. Absent an order of the Bankruptcy Court providing otherwise, substantially all pre-petition liabilities will be administered under a Chapter 11 plan of reorganization to be voted upon by creditors and other stakeholders, and approved by the Bankruptcy Court. However, under the Bankruptcy Code, regulatory or criminal proceedings are generally not subject to an automatic stay, and PG&E Corporation and the Utility expect these proceedings to continue during the pendency of the Chapter 11 Cases.

 

To assure ordinary course operations, on January 31, 2019, PG&E Corporation and the Utility received interim approval from the Bankruptcy Court on a variety of “first day” motions, including motions that authorize them to maintain their existing cash management system, to continue wage and salary payments and other benefits to their employees, to secure debtor in possession financing and other customary relief. On February 27, 2019, PG&E Corporation and the Utility received final approval of the first day motion to continue wage and salary payments and other benefits to their employees (with one limited objection with respect to a discrete matter having been preserved by the Bankruptcy Court) and certain other first day motions for customary relief. Hearings on certain other first day motions, including a hearing to consider final approval of PG&E Corporation’s and the Utility’s motions to continue their existing cash management system and to approve their debtor in possession financing, have not been held and no assurances can be given that the Bankruptcy Court will approve such motions on a final basis. PG&E Corporation and the Utility are unable to predict the date of the final hearing with respect to such motions, but there are hearings currently scheduled for March 12, March 13 and March 27, 2019.

 

In connection with the Chapter 11 Cases, PG&E Corporation and the Utility entered into the DIP Credit Agreement. See Note 4 above for a description of the DIP Credit Agreement.

 

The commencement of the Chapter 11 Cases constituted an event of default or termination event, and caused an automatic and immediate acceleration of the Accelerated Direct Financial Obligations. Accordingly, as a result of the commencement of the Chapter 11 Cases, the principal amount of the Accelerated Direct Financial Obligations, together with accrued interest thereon, and in case of certain indebtedness, premium, if any, thereon, immediately became due and payable. However, any efforts to enforce such payment obligations are automatically stayed as of the Petition Date, and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The material Accelerated Direct Financial Obligations include the outstanding senior notes, agreements in respect of certain series of pollution control bonds, and PG&E Corporation's term loan facility, as well as short-term borrowings under PG&E Corporation's and the Utility's revolving credit facilities and the Utility's term loan facility disclosed in Note 4 above. The filing of the Chapter 11 Cases may also provide the counterparties under certain commodity and related agreements with the right to declare an event of default and to seek termination of such rights subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

 

Under the priority scheme established by the Bankruptcy Code, certain post-petition and secured or “priority” pre-petition liabilities need to be satisfied before general unsecured creditors and holders of PG&E Corporation's and the Utility’s equity are entitled to receive any distribution. No assurance can be given as to what values, if any, will be ascribed in the Chapter 11 Cases to the claims and interests of each of these constituencies. Additionally, no assurance can be given as to whether, when or in what form unsecured creditors and holders of PG&E Corporation’s or the Utility’s equity may receive a distribution on such claims or interests.

 

Under the Bankruptcy Code, PG&E Corporation and the Utility may assume, assume and assign, or reject certain executory contracts and unexpired leases, including, without limitation, leases of real property and equipment, subject to the approval of the Bankruptcy Court and to certain other conditions. Any description of an executory contract or unexpired lease in this Annual Report on Form 10-K, including, where applicable, the express termination rights thereunder or a quantification of their obligations, must be read in conjunction with, and is qualified by, any overriding rejection rights PG&E Corporation and the Utility have under the Bankruptcy Code.

 

As of February 28, 2019, the Utility had outstanding borrowings of $350 million under the DIP Revolving Facility and $30 million in face amount of outstanding letters of credit, with remaining availability of $1.12 billion under the DIP Revolving Facility.

 

US District Court Matters and Probation

 

On August 9, 2016, the jury in the federal criminal trial against the Utility in the United States District Court for the Northern District of California, in San Francisco, found the Utility guilty on one count of obstructing a federal agency proceeding and five counts of violations of pipeline integrity management regulations of the Natural Gas Pipeline Safety Act. On January 26, 2017, the court issued a judgment of conviction against the Utility. The court sentenced the Utility to a 5-year corporate probation period, oversight by a third-party monitor for a period of five years, with the ability to apply for early termination after 3 years, a fine of $3 million to be paid to the federal government, certain advertising requirements, and community service.

 

The probation includes a requirement that the Utility not commit any local, state, or federal crimes during the probation period. As part of the probation, the Utility has retained a third-party monitor at the Utility’s expense. The goal of the third-party monitor is to help ensure that the Utility takes reasonable and appropriate steps to maintain the safety of its gas and electric operations, and to maintain effective ethics, compliance and safety related incentive programs on a Utility-wide basis.

 

On November 27, 2018, the court overseeing the Utility’s probation, issued an order requiring that the Utility, the United States Attorney’s Office for the Northern District of California (the “USAO”) and the third-party monitor provide written answers to a series of questions regarding the Utility’s compliance with the terms of its probation, including what requirements of the Utility’s probation “might be implicated were any wildfire started by reckless operation or maintenance of PG&E power lines” or “might be implicated by any inaccurate, slow, or failed reporting of information about any wildfire by PG&E.”  The court also ordered the Utility to provide “an accurate and complete statement of the role, if any, of PG&E in causing and reporting the recent 2018 Camp fire in Butte County and all other wildfires in California” since January 2017 (“Question 4 of the November 27 Order”).  On December 5, 2018, the court issued an order requesting that the Office of the California Attorney General advise the court of its view on “the extent to which, if at all, the reckless operation or maintenance of PG&E power lines would constitute a crime under California law.”  The responses of the Attorney General were submitted on December 28, 2018, and the responses of the Utility, the USAO and the third-party monitor were submitted on December 31, 2018.

 

On January 3, 2019, the court issued a new order requiring that the Utility provide further information regarding the Atlas fire.  The court noted that “[t]his order postpones the question of the adequacy of PG&E’s response” to Question 4 of the November 27 Order.  On January 4, 2019, the court issued another order requiring that the Utility provide “with respect to each of the eighteen October 2017 Northern California wildfires that [Cal Fire] has attributed to [the Utility’s] facilities,” information regarding the wind conditions in the vicinity of each fire’s origin and information about the equipment allegedly involved in each fire’s ignition.  The responses of the Utility were submitted on January 10, 2019.

 

On January 9, 2019, the court ordered the Utility to appear in court on January 30, 2019, as a result of the court’s finding that “there is probable cause to believe there has been a violation of the conditions of supervision” with respect to reporting requirements related to the 2017 Honey fire.  In addition, on January 9, 2019, the court issued an order (the “January 9 Order”) proposing to add new conditions of probation that would require the Utility, among other things, to:

 

  • prior to June 21, 2019, “re-inspect all of its electrical grid and remove or trim all trees that could fall onto its power lines, poles or equipment in high-wind conditions, . . . identify and fix all conductors that might swing together and arc due to slack and/or other circumstances under high-wind conditions[,] identify and fix damaged or weakened poles, transformers, fuses and other connectors [and] identify and fix any other condition anywhere in its grid similar to any condition that contributed to any previous wildfires”,

 

  • “document the foregoing inspections and the work done and . . . rate each segment’s safety under various wind conditions” and

 

  • at all times from and after June 21, 2019, “supply electricity only through those parts of its electrical grid it has determined to be safe under the wind conditions then prevailing.”

 

The Utility was ordered to show cause by January 23, 2019, as to why the Utility’s conditions of probation should not be modified as proposed. The Utility's response was submitted on January 23, 2019. The court requested that Cal Fire file a public statement, and invited the CPUC to comment, by January 25, 2019. On January 30, 2019, the court found that the Utility had violated a condition of its probation with respect to reporting requirements related to the 2017 Honey fire. The court issued an order stating that a sentencing hearing on the probation violation will be set at a later date. The court also invited parties to comment by February 20, 2019, on the 2019 Wildfire Safety Plan that the Utility submitted to the CPUC on February 6, 2019.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
  1. Report in columns (b),(c),(d) 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.
  4. Report data on a year-to-date basis.
Line No.
Item
(a)
Unrealized Gains and Losses on Available-For-Sale Securities
(b)
Minimum Pension Liability Adjustment (net amount)
(c)
Foreign Currency Hedges
(d)
Other Adjustments
(e)
Other Cash Flow Hedges Interest Rate Swaps
(f)
Other Cash Flow Hedges [Specify]
(g)
Totals for each category of items recorded in Account 219
(h)
Net Income (Carried Forward from Page 116, Line 78)
(i)
Total Comprehensive Income
(j)
1
Balance of Account 219 at Beginning of Preceding Year
2,433,257
2,433,257
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
520,640
520,640
3
Preceding Quarter/Year to Date Changes in Fair Value
3,336,770
3,336,770
4
Total (lines 2 and 3)
3,857,410
3,857,410
1,691,270,758
1,695,128,168
5
Balance of Account 219 at End of Preceding Quarter/Year
6,290,667
6,290,667
6
Balance of Account 219 at Beginning of Current Year
6,290,667
6,290,667
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
1,479,837
1,479,837
8
Current Quarter/Year to Date Changes in Fair Value
5,797,538
5,797,538
9
Total (lines 7 and 8)
7,277,375
7,277,375
6,818,107,469
6,825,384,844
10
Balance of Account 219 at End of Current Quarter/Year
986,708
986,708


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in column (h) common function.

Line No.
Classification
(a)
Total Company For the Current Year/Quarter Ended
(b)
Electric
(c)
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other (Specify)
(g)
Common
(h)
1
UtilityPlantAbstract
UTILITY PLANT
2
UtilityPlantInServiceAbstract
In Service
3
UtilityPlantInServiceClassified
Plant in Service (Classified)
74,125,476,600
54,086,032,049
13,916,406,240
6,123,038,311
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
18,230,721
18,230,721
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
175,153
5,412
180,565
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
12,823,811,035
7,129,231,035
5,175,470,140
519,109,860
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
Total (3 thru 7)
86,967,343,203
61,215,268,496
19,091,695,815
6,660,378,892
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
11
ConstructionWorkInProgress
Construction Work in Progress
2,562,027,669
1,720,845,397
352,902,795
488,279,477
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
13
UtilityPlantAndConstructionWorkInProgress
Total Utility Plant (8 thru 12)
89,529,370,872
62,936,113,893
19,444,598,610
7,148,658,369
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
37,353,599,037
26,907,643,431
7,703,873,367
2,742,082,239
15
UtilityPlantNet
Net Utility Plant (13 less 14)
52,175,771,835
36,028,470,462
11,740,725,243
4,406,576,130
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
36,332,965,571
26,845,549,665
7,696,385,371
1,791,030,535
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
8,525,339
8,525,339
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
1,012,108,127
62,093,766
1,037,343
951,051,704
22
DepreciationAmortizationAndDepletionUtilityPlantInService
Total in Service (18 thru 21)
37,353,599,037
26,907,643,431
7,703,873,367
2,742,082,239
23
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthersAbstract
Leased to Others
24
DepreciationUtilityPlantLeasedToOthers
Depreciation
25
AmortizationAndDepletionUtilityPlantLeasedToOthers
Amortization and Depletion
26
DepreciationAmortizationAndDepletionUtilityPlantLeasedToOthers
Total Leased to Others (24 & 25)
27
DepreciationAndAmortizationUtilityPlantHeldForFutureUseAbstract
Held for Future Use
28
DepreciationUtilityPlantHeldForFutureUse
Depreciation
29
AmortizationUtilityPlantHeldForFutureUse
Amortization
30
DepreciationAndAmortizationUtilityPlantHeldForFutureUse
Total Held for Future Use (28 & 29)
31
AbandonmentOfLeases
Abandonment of Leases (Natural Gas)
32
AmortizationOfPlantAcquisitionAdjustment
Amortization of Plant Acquisition Adjustment
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Total Accum Prov (equals 14) (22,26,30,31,32)
37,353,599,037
26,907,643,431
7,703,873,367
2,742,082,239


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157)
  1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent.
  2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.
Line No.
Description of item
(a)
Balance Beginning of Year
(b)
Changes during Year Additions
(c)
Changes during Year Amortization
(d)
Changes during Year Other Reductions (Explain in a footnote)
(e)
Balance End of Year
(f)
1
Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)
2
Fabrication
3
Nuclear Materials
261,763,030
78,340,869
(a)
106,154,666
233,949,233
4
Allowance for Funds Used during Construction
5
(Other Overhead Construction Costs, provide details in footnote)
6
SUBTOTAL (Total 2 thru 5)
261,763,030
78,340,869
106,154,666
233,949,233
7
Nuclear Fuel Materials and Assemblies
8
In Stock (120.2)
9
In Reactor (120.3)
416,084,176
106,154,666
(b)
94,857,220
427,381,622
10
SUBTOTAL (Total 8 & 9)
416,084,176
106,154,666
427,381,622
11
Spent Nuclear Fuel (120.4)
2,265,141,307
94,857,219
2,359,998,526
12
Nuclear Fuel Under Capital Leases (120.6)
13
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
2,505,050,242
125,886,537
2,630,936,779
14
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
437,938,271
279,352,754
125,886,537
201,011,886
390,392,602
15
Estimated Net Salvage Value of Nuclear Materials in Line 9
16
Estimated Net Salvage Value of Nuclear Materials in Line 11
17
Est Net Salvage Value of Nuclear Materials in Chemical Processing
18
Nuclear Materials held for Sale (157)
19
Uranium
20
Plutonium
21
Other (Provide details in footnote)
22
TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NuclearMaterialsNuclearFuelInProcessOfRefinementConversionEnrichmentAndFabricationOtherReductions

Cost of fuel inserted into reactor during 2018; cost transferred from Nuclear Fuel in Process to Nuclear Fuel in Reactor.

(b) Concept: NuclearFuelAssembliesInReactorOtherReductions

Cost of spent fuel transferred from Nuclear Fuel in Reactor to Spent Nuclear Fuel in 2018.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
  1. Report below the original cost of electric plant in service according to the prescribed accounts.
  2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
  3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
  4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and reductions in column (e) adjustments.
  5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
  6. 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) 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 Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent’s plant actually in service at end of year.
  7. 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, include in column (e) the amounts with respect to accumulated provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary account classifications.
  8. 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 requirement of these pages.
  9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance at End of Year
(g)
1
1. INTANGIBLE PLANT
2
(301) Organization
3
(302) Franchise and Consents
113,935,938
24,823,199
138,759,137
4
(303) Miscellaneous Intangible Plant
4,126,232
1,166,068
3,389
5,288,911
5
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
118,062,170
25,989,267
3,389
144,048,048
6
2. PRODUCTION PLANT
7
A. Steam Production Plant
8
(310) Land and Land Rights
8,644,205
8,644,205
9
(311) Structures and Improvements
113,561,273
109,771
113,671,044
10
(312) Boiler Plant Equipment
276,508,417
2,442,743
989,383
277,961,777
11
(313) Engines and Engine-Driven Generators
12
(314) Turbogenerator Units
257,380,332
257,380,332
13
(315) Accessory Electric Equipment
52,595,986
29,565
52,625,551
14
(316) Misc. Power Plant Equipment
28,348,904
28,348,904
15
(317) Asset Retirement Costs for Steam Production
96,102,035
96,102,035
16
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
833,141,152
2,582,079
989,383
834,733,848
17
B. Nuclear Production Plant
18
(320) Land and Land Rights
22,726,561
22,726,561
19
(321) Structures and Improvements
1,085,772,994
6,835,729
3,353,723
1,089,255,000
20
(322) Reactor Plant Equipment
3,517,473,860
71,354,380
10,522,065
3,578,306,175
21
(323) Turbogenerator Units
1,170,599,139
7,411,227
3,261,577
1,174,748,789
22
(324) Accessory Electric Equipment
846,769,572
21,188,894
66,467
867,891,999
23
(325) Misc. Power Plant Equipment
1,147,664,525
41,690,752
25,947,697
1,163,407,580
24
(326) Asset Retirement Costs for Nuclear Production
2,272,616,627
1,092,350,056
3,364,966,683
25
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
10,063,623,278
148,480,982
43,151,529
1,092,350,056
11,261,302,787
26
C. Hydraulic Production Plant
27
(330) Land and Land Rights
42,302,196
409,562
8,974
42,702,784
28
(331) Structures and Improvements
499,373,873
29,748,058
3,410,063
525,711,868
29
(332) Reservoirs, Dams, and Waterways
2,079,068,411
40,774,259
1,296,654
4,728,569
2,123,274,585
30
(333) Water Wheels, Turbines, and Generators
954,260,058
68,183,816
10,722,940
1,011,720,934
31
(334) Accessory Electric Equipment
271,049,293
27,932,714
2,865,660
296,116,347
32
(335) Misc. Power Plant Equipment
94,926,142
8,559,531
1,063,343
102,422,330
33
(336) Roads, Railroads, and Bridges
85,007,646
8,146,421
17,742
93,136,325
34
(337) Asset Retirement Costs for Hydraulic Production
7,200,427
7,200,427
35
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
4,033,188,046
183,754,361
19,385,376
4,728,569
4,202,285,600
36
D. Other Production Plant
37
(340) Land and Land Rights
19,207,870
19,207,870
38
(341) Structures and Improvements
210,604,019
200,429
210,804,448
39
(342) Fuel Holders, Products, and Accessories
11,271,196
11,271,196
40
(343) Prime Movers
226,088,318
803,368
989,383
227,881,069
41
(344) Generators
353,681,235
197,027
353,878,262
42
(345) Accessory Electric Equipment
212,857,732
856,942
213,714,674
43
(346) Misc. Power Plant Equipment
97,457,928
1,188,085
98,646,013
44
(347) Asset Retirement Costs for Other Production
44.1
(348) Energy Storage Equipment - Production
45
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44)
1,131,168,298
3,245,851
989,383
1,135,403,532
46
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
16,061,120,774
338,063,273
62,536,905
1,092,350,056
4,728,569
17,433,725,767
47
3. Transmission Plant
48
(350) Land and Land Rights
276,608,506
684,064
1,490
277,291,080
48.1
(351) Energy Storage Equipment - Transmission
49
(352) Structures and Improvements
461,242,771
34,815,270
496,058,041
50
(353) Station Equipment
6,170,545,480
481,497,306
41,550,592
822,172
6,609,670,022
51
(354) Towers and Fixtures
916,974,214
47,048,198
2,188,965
961,833,447
52
(355) Poles and Fixtures
1,174,526,222
211,430,662
4,322,481
1,381,634,403
53
(356) Overhead Conductors and Devices
1,535,926,474
184,432,168
7,297,467
1,713,061,175
54
(357) Underground Conduit
504,865,156
7,335,852
1,024,869
511,176,139
55
(358) Underground Conductors and Devices
272,635,262
1,728,574
343,845
274,019,991
56
(359) Roads and Trails
86,759,267
7,594,898
94,354,165
57
(359.1) Asset Retirement Costs for Transmission Plant
3,988,851
2,354,516
1,634,335
58
TOTAL Transmission Plant (Enter Total of lines 49 thru 59)
11,404,072,203
976,566,992
56,729,709
3,176,688
12,320,732,798
59
4. Distribution Plant
60
(360) Land and Land Rights
175,062,439
5,593,729
5,329
180,650,839
61
(361) Structures and Improvements
327,090,066
742,753
254,994
4,728,569
322,849,256
62
(362) Station Equipment
3,354,258,444
191,731,907
33,300,743
125,567
3,512,564,041
63
(363) Energy Storage Equipment – Distribution
33,232,585
264,688
33,497,273
64
(364) Poles, Towers, and Fixtures
4,323,200,397
542,735,774
33,207,217
4,832,728,954
65
(365) Overhead Conductors and Devices
4,690,443,433
257,144,056
147,761,741
4,799,825,748
66
(366) Underground Conduit
2,861,362,449
142,249,470
59,432
3,003,552,487
67
(367) Underground Conductors and Devices
4,554,288,320
261,215,464
8,883,910
4,806,619,874
68
(368) Line Transformers
3,451,398,731
365,166,596
25,838,062
3,790,727,265
69
(369) Services
3,272,328,566
151,958,578
2,107,371
3,422,179,773
70
(370) Meters
1,157,714,458
55,069,449
11,503,350
1,201,280,557
71
(371) Installations on Customer Premises
27,313,912
756,690
28,070,602
72
(372) Leased Property on Customer Premises
895,448
895,448
73
(373) Street Lighting and Signal Systems
231,835,835
22,931,564
31,017
254,736,382
74
(374) Asset Retirement Costs for Distribution Plant
15,233,800
8,940,961
6,292,839
75
TOTAL Distribution Plant (Enter Total of lines 62 thru 76)
28,475,658,883
1,997,560,718
262,953,166
9,066,528
4,728,569
30,196,471,338
76
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77
(380) Land and Land Rights
78
(381) Structures and Improvements
79
(382) Computer Hardware
80
(383) Computer Software
81
(384) Communication Equipment
82
(385) Miscellaneous Regional Transmission and Market Operation Plant
83
(386) Asset Retirement Costs for Regional Transmission and Market Oper
84
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85
6. General Plant
86
(389) Land and Land Rights
424,632
424,632
87
(390) Structures and Improvements
11,254,863
522,272
11,777,135
88
(391) Office Furniture and Equipment
15,628,644
215,865
414,288
15,430,221
89
(392) Transportation Equipment
90
(393) Stores Equipment
91
(394) Tools, Shop and Garage Equipment
129,933,249
15,424,364
145,357,613
92
(395) Laboratory Equipment
14,556,151
1,471,911
121,553
15,906,509
93
(396) Power Operated Equipment
271,024
271,024
94
(397) Communication Equipment
291,009,027
77,704,741
463,072
368,250,696
95
(398) Miscellaneous Equipment
70,772,401
16,144,550
1,510,994
1,694,626
87,100,583
96
SUBTOTAL (Enter Total of lines 86 thru 95)
533,849,991
111,483,703
2,780,931
1,694,626
644,247,389
97
(399) Other Tangible Property
468,499,422
468,499,422
98
(399.1) Asset Retirement Costs for General Plant
7,292,156
246,166
7,538,322
99
TOTAL General Plant (Enter Total of lines 96, 97, and 98)
1,009,641,569
111,483,703
2,780,931
1,940,792
1,120,285,133
100
TOTAL (Accounts 101 and 106)
57,068,555,599
3,449,663,953
385,004,100
1,082,047,632
61,215,263,084
101
(102) Electric Plant Purchased (See Instr. 8)
102
(Less) (102) Electric Plant Sold (See Instr. 8)
219,416
224,828
5,412
103
(103) Experimental Plant Unclassified
104
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
57,068,336,183
3,449,663,953
385,004,100
1,082,272,460
61,215,268,496


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC PLANT LEASED TO OTHERS (Account 104)
Line No.
LesseeName
Name of Lessee
(a)
IndicationOfAssociatedCompany
* (Designation of Associated Company)
(b)
LeaseDescription
Description of Property Leased
(c)
CommissionAuthorization
Commission Authorization
(d)
ExpirationDateOfLease
Expiration Date of Lease
(e)
ElectricPlantLeasedToOthers
Balance at End of Year
(f)
1
NONE
47
TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC 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 $250,000 or more. Group other items of property held for future use.
  2. For property having an original cost of $250,000 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.
ElectricPlantHeldForFutureUseDescription
Description and Location of Property
(a)
ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Date Originally Included in This Account
(b)
ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Date Expected to be used in Utility Service
(c)
ElectricPlantHeldForFutureUse
Balance at End of Year
(d)
1 Land and Rights:
2
NONE
3
21 Other Property:
22
NONE
47 TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
  1. Report below descriptions and balances at end of year of projects in process of construction (107).
  2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see Account 107 of the Uniform System of Accounts).
  3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
Line No.
ConstructionWorkInProgressProjectDescription
Description of Project
(a)
ConstructionWorkInProgress
Construction work in progress - Electric (Account 107)
(b)
1
74001039 SAN FRAN Y (LARKIN): REPLACE 12KV SWGR
47,860,661
2
7054908 MC-P Relic- Project Management
38,252,003
3
68011748 PLO-U2:Repl Main Generator Stator
37,302,124
4
74000916 KERN PP: UPGRADE 230 KV BUS
34,011,822
5
74015944 EMBARCADERO (SF-Z) DECOUPLE BKS 1, 3, 5
24,225,606
6
7070913 DS conduct Rel studies
23,593,525
7
74001857 EL CERRITO G: 115KV BUS UPGRADE PHASE 1
22,076,849
8
74004821 VACA DIXON: REP 500 KV SERIES CAP BK 2
20,143,416
9
74000600 FULTON-FITCH MTN. RECOND 60KV LN
16,298,171
10
7021725 UNFFR Relic Routine Project Management
16,293,482
11
74000924 ESTRELLA_CPUC LIC/PER
15,863,538
12
74003442 MOSS LANDING: REPLACE 500 KV BREAKERS
14,111,604
13
74000925 MIDWAY ANDREW_CPUC LIC/PER
14,024,624
14
74001031 MIDWAY-KERN PP #2 230 KV LINE KERN AREA
13,946,561
15
74002444 GATES: REPL BK 500/230 KV TRANSFORMER
13,843,748
16
74002376 BORDEN 230 KV VOLTAGE SUPPORT (SUB)
13,574,688
17
74002462 PEASE - 115KV BUS TO BAAH RECONFIG
13,493,496
18
7026033 UNFFR Relic Aquatic Resource Stdy
12,909,427
19
74000841 HERNDON-KEARNEY 230 KV LINE RECONDUCTOR
12,236,016
20
13004820 Drum Spaulding - Developing PAD and NOI
12,088,194
21
74002892 VACA DIXON: REP 500 KV SERIES CAP BK 1
11,980,879
22
74000846 METCALF - EVERGREEN RECONDUCTORING (TL)
11,662,602
23
74001780 RIO OSO: INSTALL 230KV BAAH/GIS
11,614,759
24
74001097 COOLEY LANDING: INSTALL BK 2
11,606,728
25
74001782 RIO OSO: INSTALL 115 KV BAAH/GIS
11,559,275
26
74000662 VALLEJO B: REPLACE 4KV SWGR & BANKS
11,532,821
27
74001858 EL CERRITO G: REPL 12KV CBS W/SWGR
11,304,634
28
74001957 MONTA VISTA: UPGRADE 230 KV BUS - PH 1
11,289,147
29
74003144 BELLOTA: INSTALL 230 KV SHUNT REACTOR
11,272,940
30
74000939 WRJ NONCOMPETITIVE_CPUC LIC/PER
10,818,407
31
74001389 SMYRNA-SEMITROP-MIDWAY 115KV NERC ALERT
10,453,243
32
74001953 SAN FRAN F (MARINA): REPLACE 4KV SWGR
10,098,274
33
74003358 PIT PH 1: ADD BK 5
9,844,074
34
74011380 74011380_GREATER BAY ER STORAGE FAC SF
9,786,344
35
74000901 MARTIN BUS EXTENSION_CPUC LIC/PER
9,773,092
36
74002346 MARYSVILLE SUB: CONVERT TO RING BUS
9,559,341
37
74011760 NETWORK SCADA Y-2
9,381,992
38
68053001 COM: Integrated Video Mgt System Upgrade
9,324,636
39
74001398 60-SOUTH OF PALERMO REINFORCEMENT (PH-3)
9,058,695
40
74007941 CALTRAIN INTERCONNECTIONS SUB SITE 3
9,055,298
41
74001223 REDWOOD CITY: REP CB404,406,408,409,410
9,012,860
42
74001396 60-SOUTH OF PALERMO REINFORCEMENT (PH-2)
8,974,429
43
74000988 CASTRO VALLEY: REPLACE 12 KV SWITCHGEAR
8,788,097
44
74010530 74010530 GREATER BAY ER STORAGE FAC OAK
8,566,174
45
13003982 DS-C Relic- Cond studies for all RA
8,517,659
46
74001785 RIO OSO: INSTALL 230 KV MPAC
8,379,509
47
74001942 KERN PP 230KV MPAC
8,334,198
48
74000933 230 KV TLINE LOCKEFORD - NEW INDUSTRIAL
8,252,391
49
74001588 ORO LOMA: INSTALL 115 KV MPAC
8,203,725
50
74000981 HERNDON SUB - NORTHERN FRESNO 115KV AREA
8,201,914
51
74006580 NV_TESLA 230KV BUS DIFFERENTIAL REPLACE
7,869,354
52
74000714 (DA-CE) COLGATE-CHALLENGE RELIABILITY
7,793,112
53
7076869 Buck Rel Studies
7,549,005
54
74001786 RIO OSO: INSTALL 115 KV MPAC
7,510,911
55
74000959 MCCALL SUB - NORTHERN FRESNO 115KV AREA
7,369,704
56
74001710 SANGER: REPLACE 115 KV BUS
7,325,398
57
74000343 CALTRAIN INTERCONNECTIONS SUB SITE 1
7,142,520
58
74001391 60-SOUTH OF PALERMO REINFORCEMENT (PH-1)
6,973,678
59
74001620 Pit 3 Unit 3 Replace Rewind
6,892,123
60
74015243 TSRP-NORTH BAY SIERRA PROJECT MANAGEMENT
6,823,920
61
74009262 KASSON SUB: REPLACE BANK 1
6,221,577
62
7026032 UNFFR Relic Water Use & Qlty Stdy
6,197,315
63
74001708 SANGER: INSTALL 115 KV MPAC
6,197,049
64
74001781 RIO OSO: INSTALL BK 1 AND BK 2
6,180,150
65
74001112 RIPON NEW 115 KV LINE 2ND TAP RELIABILIT
6,097,982
66
74001713 HUNTERS POINT: 115KV GIS BAAH
6,085,776
67
7026037 UNFFR Relic Land Use/Mgt Study
5,936,003
68
74004964 SOBRANTE: ADD & REPL 14-115KV BKERS P2
5,867,022
69
7055507 DS Relic- Strategic Planning
5,736,990
70
7055646 DS Relic- Project Management
5,702,054
71
68017320 PLO-Remove Abandoned in place RO System
5,639,241
72
74003025 IGNACIO: INSTALL 230 KV SHUNT REACTOR
5,622,270
73
74001063 GATE-GREGG 230KV T-LINE CPUC LIC/PER
5,602,736
74
74016300 NETWORK SCADA Y-1
5,523,955
75
74010662 Helms - Main Crane Modification
5,416,072
76
74004615 EAGLE ROCK-FULTON-SILVERADO NERC PROJECT
5,273,864
77
74001960 MOSS LANDING: INST 500 KV CTRL BUILDING
5,229,936
78
74001853 EL CERRITO G:REPLBK4 W/BK3 115-12KV 60MV
5,039,026
79
74010941 BORDEN: INSTALL MPAC
4,980,717
80
7089447 Potter Valley Rel Studies
4,865,138
81
74003359 MARTIN: REPLACE 230 KV SHUNT REACTOR 1
4,818,696
82
7072819 Helms - Replace Liquid Rheostat
4,775,041
83
74002483 SPENCE: INSTALL BK 1
4,523,667
84
74002743 STOCKTON A WEBER
4,508,263
85
74014700 Pit 6 U1 Replace Transformer
4,477,671
86
74009948 BELLOTA SUB: PHYSICAL SECURITY UPGRADE
4,386,447
87
68015242 PLO-COM::Rplc Secondary Chem Lab
4,310,063
88
74001472 GOLD HILL: REPLACE CB 222 242 252 212
4,300,964
89
74001436 (DA-B&M) ELECTRA-VALLEY SPRGS CAP/RECOND
4,285,069
90
74001723 PEASE - INST BANK 5
4,285,039
91
74000626 CAMANCHE TAP 115KV RECONDUCTOR
4,210,824
92
74005663 KERN PP: CONVERT 115KV BUS TO BAAH
4,102,854
93
74008620 Fordyce Dam Leakage Reduction
4,045,838
94
74006762 METCALF-SALINAS NO. 1 (IDLE) (P3)
3,914,960
95
74009504 SF M SUB, REPLACE BK 1 12KV & 4KV SWGR
3,902,068
96
74004832 WEEDPATCH 70 KV CB 42 52 62
3,888,438
97
68049386 PLO-COM: Reloc Security VIS
3,887,443
98
74001001 WHEELER RIDGE-WEEDPATCH 70 KV (KALTR)
3,867,833
99
68020200 PLO: U2: REPL CFCU CLNG COILS (2R21)2-5
3,861,388
100
74002247 ORO LOMA: REPLACE BK 2 115/70 KV
3,805,760
101
74020222 FULTON-CALISTOGA 60 KV LINE RECONDUCTORE
3,745,737
102
74000709 (DA-TRC) HUMBOLDT BAY RECOND. PROJ. 2021
3,719,903
103
74018125 SPENCE: UPGRADE TRANSMISSION 60 KV
3,695,509
104
74002930 COLUMBUS: INSTALL 2-115 KV CBS
3,682,051
105
74001175 MOSHER-LOCKFORD 60KV RECOND.
3,666,256
106
74004265 ORO LOMA: INSTALL BK 3
3,639,894
107
74011616 Helms - Rewind U2
3,637,902
108
74009760 TC Canal_Install Canal Liner 17/19
3,516,447
109
74000825 LEMOORE NAS 70 KV SCADA SW#55,65
3,397,631
110
74004888 OAKLAND D SUB: REPLACE 4KV SWITCHGEAR
3,365,135
111
74000711 NRS-SCOTT RECONDUCTORING
3,340,931
112
74001688 NC_(DA-ABB) MAPLE CREEK SUB:REACTIVE SUP
3,336,884
113
68019301 U1:Upgrade Polisher Computer Workstation
3,322,543
114
30797619 OAKLEY GENERATING STN: LAS POSITAS-NEWAR
3,305,177
115
74001432 COTTNWD-RED BLUFF - RECONDUCTOR
3,291,424
116
7049829 DC Relic Begin Prep of NOI and PAD
3,253,857
117
7026034 UNFFR Relic Terres Resources Stdy
3,250,247
118
74001453 Electra U3 New Needle, Stem & Bushings
3,244,265
119
74018362 FLINT SUB: EMER BK1 REPLACE
3,227,687
120
74004617 GEYSERS #9-LAKEVILLE NERC PROJECT
3,165,208
121
74002214 HOPLAND: REPLACE BK 2
3,119,450
122
74001179 NV_94-INDIAN FLAT SUB:REPL SW 17 W/1-70K
3,113,452
123
13006140 MC-P Relic- Conduct Relicensing Studies
3,089,012
124
74006763 METCALF-SALINAS NO. 2
3,030,268
125
74000700 TEMPLETON 230/70KV MPAC
3,022,647
126
74005020 MIDWAY: UPGRADE 230 KV BUS SECTION D
2,989,401
127
31168794 ETTM RANCHO VISTA MHP
2,959,277
128
7053945 DC Relic - Prepare Study Plans
2,939,134
129
74005023 SHAFTER SUBSTATION: BANK 1
2,938,687
130
74000731 EAST SHORE-OAKLAND J 115KV RECONDUCT(TL)
2,938,111
131
7054909 MC-P Relic- Prepare NOI and PAD
2,908,006
132
74001200 EXCHEQUER SUB TO BEAR VALLEY SUB
2,854,654
133
74001427 WEBER-SANTA FE JUNCTION 60 KV RECON
2,835,960
134
74011148 VACA DIXON: EM INSTALL STATION LIGHTING
2,782,683
135
74008580 ASHLAN: CONVERT TO 230 KV RING BUS
2,779,535
136
74005670 VALLEJO B: REPLACE 4 KV SWGR - DLINE
2,769,754
137
74004826 67-HICKS: INSTALL 230KV MPAC (CONSTR 201
2,764,927
138
74009861 BRUCE RD CHICO R20A
2,762,560
139
74001022 LERDO: REPLACE 12 KV BUS SECTION E
2,760,452
140
68044182 PLO: COM: REPL HVAC Units 501, 502, 503
2,739,325
141
74021024 MORGAN HILL SUB: 115KV BAAH CONVERSION
2,736,161
142
13008740 Battle Crk - Phase 2 License Amendment
2,732,217
143
7076872 Buck Rel Lic App
2,732,140
144
74000915 KERN 230KV AREA REIN MIDWAY-KERN 3 & 4 (
2,705,944
145
74001642 R1 MIDDLEFIELD ROAD REDWOOD CITY R20A
2,693,039
146
74015245 TSRP-NORTH BAY SIERRA ET COMM- READY SUB
2,688,328
147
13011921 NFSL Additional Design Imp
2,688,213
148
7043247 RCC Lic Imp Cold Water Feasibility Study
2,687,809
149
74001856 EL CERRITO G: 115KV BUS UPGRADE PHASE 2
2,684,935
150
74008161 2018 CARUTHERS 1102 EXTEND & REINF PH. 2
2,674,750
151
68009762 PLO-U2:Replace DG22 Exciter/Voltage Regu
2,669,044
152
74008366 MESA SUB VOLTAGE SUPPORT
2,665,296
153
74000601 FULTON-FITCH: RECONDUCTORING 60 KV
2,663,947
154
7021727 UNFFR Relic Prepare 5 Year Library
2,604,684
155
74002486 KERN PP: INSTALL 115KV MPAC BLDGS
2,597,583
156
74000936 WRJ COMPETITIVE_CPUC LIC/PER
2,577,508
157
74007560 EMBARCADERO - REPLACE 34/12KV BANK 12
2,561,630
158
74000546 KEARNEY-CARUTHERS 70 KV LINE RECONDUCTOR
2,561,447
159
30854865 NEWARK-AMES 1300FT BW 46-50 CRITTENDON
2,550,149
160
74001766 RAVENSWOOD-COOLEY LANDING 115 KV (TL)
2,532,159
161
7093246 ODN Network Segmentation
2,517,120
162
74021027 METCALF-GREEN VALLEY 115KV: LINE RECONDU
2,474,875
163
74003441 ASHLAN: INSTALL MPAC BUILDING & OPGW
2,472,488
164
74018601 GATES-TULARE LAKE 70KV EMERGENCY WORK
2,454,647
165
68019124 PLO-Com:Repl Breathing Air Compsr Ph II
2,452,174
166
13002402 DS-C Relic- Conduct Pre-App Proj Man
2,446,314
167
68000146 Lead Order-U2:Repl Boric Acid Xfer Pumps
2,443,385
168
13011869 Pit 6 Replace Stoplog Lifting Device
2,437,234
169
74001334 TEMBLOR-SAN LUIS OBISPO 115KV NERC
2,430,238
170
30842587 OAKLEY GENERATING STN:COCOPP-DELTA PUMPS
2,423,395
171
74000345 CHSR INTERCONNECTIONS SUB SITES 4-7
2,383,891
172
7026036 UNFFR Relic Rec Resources Study
2,361,923
173
31214160 EM_RICHMOND Q SUB - REPL. UNIT SUBS
2,359,578
174
74001677 NV_STOCKTON A SUB- REPLACE CB 402,404
2,354,542
175
74006884 MORRO BAY SUB: UPGRADE 230KV BUS
2,345,835
176
68019302 PLO-U2:Cond. Polisher Cmptr Upgrade
2,304,229
177
74001064 GATES-GREGG PRE-BID COSTS
2,290,371
178
74000900 Bucks Creek U2 Generator Rewind
2,288,512
179
74018460 RMR: TRIMBLE-SAN JOSE B 115KV SERIES REA
2,286,635
180
68036981 PLO: COM: 500kv Road Upgrade
2,274,196
181
68050741 PLO-U1: Repl DRPI Detector/Encoder Cards
2,253,910
182
31298384 ODN SECURITY PROJECT
2,236,884
183
74000707 60 KINGSBURG-LEMOORE 70KV RECOND. PH1
2,225,234
184
74008419 Caribou 1 Crane Modernization
2,224,924
185
74001173 LODI: REPLACE CB 12 22 32
2,190,937
186
74005121 EVERGREEN SUB: 115KV BUS UPGRADE
2,190,606
187
74000341 CHSR INTERCONNECTIONS SUB SITES 8-13
2,188,887
188
74001732 VIERRA 115 KV REINFORCEMENT (T-LINE)
2,188,471
189
74007808 RICE SUB: REPLACE BANK 1
2,174,438
190
68048860 PLO - U1: Repl Plant Recorders
2,165,077
191
74008380 Cresta PH Refurbish Transformers
2,164,619
192
74008281 Bucks Cr Replace Turb Brg / Shaft
2,147,649
193
74004825 HICKS: IMPROVE 230 KV BUS RELIABILITY
2,114,460
194
13011870 Pit 7 Replace Stoplog Lifting Device
2,103,301
195
74001020 SHAFTER SUB-REPLACE CB 1101, 1102, 1103
2,093,449
196
74006361 DELEVAN: INSTALL 200 MVAR SHUNT REACTOR
2,087,161
197
74008660 2018 GATES 1110 12KV FEEDER
2,075,286
198
74001047 KERN 230KV AREA REIN MIDWAY-KERN 1 & 2 (
2,074,734
199
13009580 DeSabla Replace Governor
2,072,742
200
74015582 STUART: EM REPLACE 12/4 KV BK1
2,066,581
201
74005355 RIO OSO SUB: SVC
2,054,284
202
74008455 Cresta PH Arc Flash Remediation U1&U2
2,042,601
203
74000840 -ENG.ONLY (DA-B&M) KESWICK-TRINITY REL.
1,997,723
204
74002485 NC_PUEBLO SUB: REPLACE BK 1
1,991,741
205
74015805 LERDO: REPLACE 12 KV BUS SECTION
1,970,734
206
7026029 UNFFR Relic Prep 1st Stage Consult Pkg
1,962,278
207
74010660 Balch 2 - U2 Replace Cooling Water
1,959,326
208
68038260 PLO-COM: North Access Rd Upgrade
1,947,546
209
74001739 (CONT.EST) MAPLE CREEK-WILLOW 60KV REL.
1,944,682
210
74008524 EP BRIDGE ST COLUSA R20A
1,936,386
211
74010750 MONTA VISTA: INSTALL 230KV MPAC
1,932,577
212
74001553 EP SHELL BEACH RD PISMO BEACH R20A
1,927,008
213
74012040 NICOLAUS-WILKINS SLOUGH 60KV LINE POLE
1,919,578
214
74017519 VACA DIXON: INSTALL 230 KV SMART WIRES
1,919,282
215
74011030 KERN 230KV BAAH 115KV LINE RELOCATION
1,917,488
216
7092705 Asset Data Improvement (GIS Phasing-Sub)
1,916,059
217
68021733 PLO-U1:Replace DG 1-2 Controls System
1,916,040
218
74003803 Q954 FIFTH STANDARD SOLAR (NU) GATES
1,915,635
219
74002410 Pit 5 TGB Install Inline Oil Filtration
1,901,496
220
74008358 SAN LEANDRO U: REPLACE CB 182, 372, 382
1,897,243
221
74002321 Inskip Eagle Canyon Access Safety Improv
1,895,135
222
74001792 RED BLUFF-COLEMAN REINFORCEMENT
1,894,567
223
74010413 BORDEN VOLTAGE SUPPORT - STOREY SUB
1,881,696
224
74008456 Cresta PH Repl Stoplog Hoist
1,846,138
225
7093006 WSOC (Ramp for addl functionality)
1,846,115
226
74003903 SHEPHERD 2111 AUBERRY ROAD RECON - 2018
1,820,443
227
74016583 Electra U2 Generator Rewind
1,818,114
228
74008384 Battle Cr Salmon/Steelhead Phase 2
1,810,645
229
74001704 FIREBAUGH: INSTALL 70 KV SCADA SWITCH
1,787,843
230
74004819 COTTLE: INSTALL 2 17 KV FEEDERS
1,770,652
231
68044188 PLO: COM: Upgrd Bldg 104 Entire 5th Flr
1,761,792
232
74016341 TSRP NBS IT OTHER SITES
1,760,829
233
13023101 Butte Head Dam Road Improvements 2017
1,702,945
234
74011488 VALLEYSPRINGS-MARTELL NO.2 SCADA
1,701,544
235
74005120 EVERGREEN: UPGRADE 60 KV PROTECTION
1,657,793
236
74009204 TABLE MTN:REPL 500KV TM-ROUND MTN #1 REL
1,651,955
237
74001943 WHEELER RIDGE VOLTAGE SUPPORT (SUB)
1,626,733
238
7062249 MC-P- Proj Scoping and Study Plan Devp
1,623,336
239
7070917 DS Post App filing activities
1,620,566
240
7087874 Permit Holdover Project - Shasta-Trinity
1,579,866
241
74001735 POTRERO-MISSION #1 (A-X 1) SEISMIC RETRO
1,574,099
242
74002189 FRENCH GULCH: INSTALL D-SCADA
1,573,970
243
74016584 Tiger Creek U2 Generator Rewind
1,573,569
244
74008849 CYMRIC: INSTALL MRTU
1,573,184
245
74003501 SUMMIT: REPL 60 KV SW 37 & SW OPERATOR
1,550,888
246
74009567 HERNDON: EM REPLACE CIRCUIT BREAKER 242
1,542,679
247
68035784 PLO-U2: Rewind RCP Stator S1
1,532,679
248
74000937 MERCY SPRINGS - CANAL SS T-LINE RECONDUC
1,531,312
249
74001584 STOCKTON A: REPLACE CONTROL BUILDING
1,524,445
250
74008301 Lower Bucks Dam Resurface Face
1,522,282
251
74010323 Poe PH Deck/Roof Resurface
1,505,083
252
74003484 WILSON: INSTALL STATCOM
1,504,758
253
74015248 TSRP NBS IT NEW MPLS
1,503,871
254
74020280 OAKLAND K: EM_REPLACE ALS RTU
1,496,104
255
74009588 Pit 7 U2 Rewind
1,493,738
256
74001397 (DA-TRC)ESSEX JCT ORICK 60KV RELIABILITY
1,488,818
257
74000622 BELLOTA - WARNERVILLE RECONDUCTOR
1,485,149
258
74000505 MARTIN: 230KV BUS RETROFIT
1,472,849
259
74007647 PEASE - TLINE SUPPORT
1,470,458
260
74001098 TABLE MOUNTAIN: REPLACE 500 KV BK 1
1,470,212
261
74018320 RMR: MTN VIEW-WHISMAN-AMES PROJECT (AMES
1,466,319
262
13002403 DS-C Relic- Conduct Studies
1,465,011
263
7055645 DS Relic- Coord Study w/ NID
1,457,743
264
74001579 OAKLAND L: CUTOVER 4 KV TO 12 KV
1,449,832
265
35047949 Z-1113 CIRCUIT RECONDUCTOR
1,447,405
266
74010363 KERN PP - LIVE OAK 115KV PROJECT
1,446,453
267
74001733 POTRERO-LARKIN #2 (A-Y2) SEISMIC RETROFI
1,437,707
268
74001734 MARTIN-LARKIN #1 115 KV CABLE (H-Y 1)
1,437,233
269
74009587 Pit 1 U1 Rewind Generator
1,436,015
270
74001855 EL CERRITO G: 115KV BUS UPGRADE T-LINE
1,428,078
271
68021224 PLO- U1:Replace AFW Chem Inj Pmp
1,421,077
272
74009061 WESTPARK: INSTALL MPAC BUILDING
1,416,659
273
74008750 HP-3 GROUNDING PROJECT
1,411,402
274
74001802 PIT PH 1: REPLACE 230 KV BK 1
1,411,046
275
74003261 Caribou 1 U1 Rewind
1,410,606
276
74014522 ORO LOMA: UPGRADE 70 KV BUS
1,408,897
277
7093170 Wildfire Wire Down detection
1,398,790
278
7049828 DC Relic Project Management
1,394,967
279
31155972 OSM EBOSS COFUNDING
1,390,463
280
74004618 SILVERADO-FULTON JCT 115KV NERC
1,384,455
281
74008009 WILSON-LEGRAND 115KV LINE RECON TL - DO
1,383,073
282
74015260 CASCADE: INSTALL BK 2 PHASE 1
1,381,063
283
74011982 MISSION BLVD DIST 30 HAYWARD R20A
1,380,843
284
74001686 NC_MAPLE CREEK PROJ-BUS RECONFIGURATION
1,369,960
285
13006781 DeSabla-Centerville Proj Mgmt Post LA
1,353,139
286
74003600 Helms Replace Load Center 1, 2, 7 & 8
1,331,654
287
7089886 Kerckhoff Rel PAD and NOI
1,320,555
288
74011243 IGNACIO-MARE ISL 115KV (HWY SUB/COR SUB)
1,301,384
289
74002796 COCO: REPLACE D-SCADA
1,290,923
290
74015249 TSRP-NORTH BAY SIERRA ET MPAC/HMI SUBSTA
1,278,712
291
74009901 Rock Cr PH U1 & U2 Repl WG Seals
1,248,879
292
74010362 PILOT: SAN BRUNO INT PIPE-TYPE UG CABLE
1,232,203
293
74015247 TSRP-NORTH BAY SIERRA ET NEW COMM SYSTEM
1,231,725
294
74001486 GRIZZLY PEAK BLVD BERKELEY R20A
1,223,680
295
74006664 RICE: EM REPLACE UNIT SUB 2
1,217,800
296
74010464 OLIVE SW STA-SMYRNA 115KV MAINTENANCE RE
1,201,884
297
74009501 Tiger Crk Abay LLO Gate Replace
1,197,997
298
74008922 VACA-TULUCAY-LAKEVILLE 230KV-NERC
1,196,386
299
74002547 Kings River PH - Replace Governor
1,188,342
300
74008421 Bucks Cr Modify 2 Cranes
1,180,523
301
74003069 LOS ESTEROS SHUNT REACTOR PROJECT
1,178,722
302
74003661 Bucks Creek U1 Generator Stator Rewind
1,178,121
303
74002167 HYAMPOM JCT: INSTALL T-SCADA CB 62
1,172,437
304
74001089 STOCKDALE 230 KV TAP #1 AND #2 FROM THE
1,169,293
305
31168741 ETTM MOREHEAD PARK
1,166,730
306
74004481 +MESA 1104 FEEDER - PHASE 1
1,161,207
307
74007445 Q1036 MUSTANG 2 (NU) 230 KV SS
1,154,391
308
74004508 LAKEWOOD SUB: REPLACE BANK 5
1,154,272
309
74001392 SOUTH OF PALERMO - PALERMO SUB
1,147,870
310
74002206 GLENN: REPLACE BK 1
1,147,214
311
74000665 BRIGHTON-GRAND ISLAND #1 & #2 115KV NERC
1,139,328
312
74008385 Coleman Decommission Asbury Pipe
1,136,821
313
74000733 CARIBOU-BIG BEND 115KV NERC
1,136,383
314
74014400 ASHLAN: REROUTE 230KV T-LINES
1,121,417
315
7093366 Dist Resources Planning Tools MA
1,114,320
316
7076871 Buck Rel Draft Lic App
1,113,730
317
74007447 PANOCHE-ORO LOMA 115 KV LINE RECONDUCTOR
1,108,160
318
74003620 Cresta PH Repl Tailrace Gates
1,102,409
319
74002545 Kings River - Repl Exciter
1,097,417
320
74009027 POTRERO: REPLACE SVC CONTROLLER
1,089,778
321
74003560 SKAGGS ISLAND: REM SUB
1,085,831
322
68045340 PLO: COM:ACCESS RD COMMUNICATIONS
1,081,955
323
74002818 KIRKER: INSTALL D-SCADA 2200
1,078,043
324
74003761 Rock Cr PH Repl Tailrace Gates
1,076,103
325
31234874 RELIAIBLITY 2017 - UWF VARIOUS CKTS
1,074,933
326
74004443 PITTSBURG: REPLACE CB 352 362
1,069,212
327
74002965 OAKLAND X: UPGD 115KV DIFF EDRS#: 201
1,068,652
328
74008666 EL CERRITO G: INST 12KV FDR OUTLET, PH 1
1,064,661
329
74010465 SMYRNA-SEMITROPIC-MIDWAY 115KV MAINTENAN
1,042,962
330
74001560 OAKLAND L: INSTALL 406, 407 CUTOVER 4KV
1,041,777
331
74010343 MARTIN: REPLACE 4KV SWITCHGEAR
1,041,281
332
74008383 Coleman Tailrace Barrier Trashrake
1,034,131
333
74009203 ROUND MTN: REPL 500KV RM-TAB MTN #1 REL
1,029,901
334
30978746 MUNI CENTRAL SUBWAY-CHINA TOWN STATI
1,029,226
335
74015486 ESTRELLA CPUC DATA REQUEST #3
1,028,982
336
74002176 CRESCENT MILLS: INSTALL D-SCADA CB210
1,012,873
337
See footnote for detail.
(a)
268,814,896
43
1,720,845,397


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: ConstructionWorkInProgress

This is the aggregate total of projects with less than $1,000,000 in actual costs in Construction Work in Progress, including credits representing preliminary billings.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC 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 11, column (c), and that reported for electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable 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.
Line No.
Item
(a)
Total (c + d + e)
(b)
Electric Plant in Service
(c)
Electric Plant Held for Future Use
(d)
Electric Plant Leased To Others
(e)
Section A. Balances and Changes During Year
1
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance Beginning of Year
25,630,993,906
25,630,993,906
2
Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
2,121,424,880
2,121,424,880
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
5
ExpensesOfElectricPlantLeasedToOthers
(413) Exp. of Elec. Plt. Leas. to Others
6
TransportationExpensesClearing
Transportation Expenses-Clearing
7
OtherClearingAccounts
Other Clearing Accounts
8
OtherAccounts
Other Accounts (Specify, details in footnote):
9.1
Reverse Common Allocation
149,778,194
149,778,194
10
DepreciationProvision
TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)
1,971,646,686
1,971,646,686
11
Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
385,000,708
(a)
385,000,708
13
CostOfRemovalOfPlant
Cost of Removal
292,499,258
292,499,258
14
SalvageValueOfRetiredPlant
Salvage (Credit)
8,843,414
8,843,414
15
NetChargesForRetiredPlant
TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)
668,656,552
668,656,552
16
OtherAdjustmentsToAccumulatedDepreciation
Other Debit or Cr. Items (Describe, details in footnote):
17.1
88,434,375
(b)
88,434,375
18
BookCostOfAssetRetirementCosts
Book Cost or Asset Retirement Costs Retired
19
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18)
26,845,549,665
26,845,549,665
Section B. Balances at End of Year According to Functional Classification
20
AccumulatedDepreciationSteamProduction
Steam Production
309,485,888
309,485,888
21
AccumulatedDepreciationNuclearProduction
Nuclear Production
6,706,852,865
6,706,852,865
22
AccumulatedDepreciationHydraulicProductionConventional
Hydraulic Production-Conventional
1,403,250,911
1,403,250,911
23
AccumulatedDepreciationHydraulicProductionPumpedStorage
Hydraulic Production-Pumped Storage
774,777,368
774,777,368
24
AccumulatedDepreciationOtherProduction
Other Production
329,161,699
329,161,699
25
AccumulatedDepreciationTransmission
Transmission
3,155,263,008
(c)
3,155,263,008
26
AccumulatedDepreciationDistribution
Distribution
13,577,519,257
13,577,519,257
27
AccumulatedDepreciationRegionalTransmissionAndMarketOperation
Regional Transmission and Market Operation
28
AccumulatedDepreciationGeneral
General
589,238,669
589,238,669
29
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
TOTAL (Enter Total of lines 20 thru 28)
26,845,549,665
26,845,549,665


FOOTNOTE DATA

(a) Concept: BookCostOfRetiredPlant

This reconciles with the cost of plant retired shown on pages 204-207, column (d), as follows:

 

Book cost of Depreciable Plant Retired 385,000,708

Book cost of Amortizable Plant Retired 3,392

Total 385,004,100

Book cost of Plant Retired, pages 204-207, column (d) 385,004,100

Difference 0

(b) Concept: OtherAdjustmentsToAccumulatedDepreciation

Other Debit or Cr. Items (Describe):

 

FAS 143 Assets Depreciation (Nuclear & Fossil) 77,880,295

Decommissioning reclass to Regulatory Liability (Nuclear & Fossil) (20,583,693)

FIN 47 Asset Depreciation (EDP, EHP, ETP, EGP) (6,604,973)

Capital Lease Obligations (141,012,099)

Mirant Adjustment 2,260,506

Gain/Loss (379,294)

Reserve Adjustment 4,883

Total (88,434,375)

(c) Concept: AccumulatedDepreciationTransmission

FAS 109 Gross-up on Diablo Canyon Power Plant Utility Asset I is included in General Plant.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, 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 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 adjustment includible in column (f).
  8. Report on Line 42, 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 of 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
Eureka Energy Company
2
Common Stock
1,000
1,000
3
Additional Paid in Capital
3,741,892
3,734,531
4
Undistributed Earnings
22,796
67,037
44,241
5
SUBTOTAL
3,765,688
67,037
3,691,290
6
Natural Gas Corporation of California
7
Common Stock
100,000
100,000
8
Additional Paid in Capital
3,037,432
3,037,432
9
Undistributed Earnings
3,137,432
3,137,432
10
SUBTOTAL
11
Pacific Energy Fuels Company
12
Common Stock
10,000
10,000
13
Additional Paid in Capital
4,698,621
4,890,952
14
Undistributed Earnings
4,700,407
72,346
5,102,693
15
SUBTOTAL
8,214
72,346
201,741
16
Standard Pacific Gas Line Incorporated
17
Common Stock
1,200
1,200
18
Additional Paid in Capital
43,473,426
45,889,873
19
Undistributed Earnings
27,145,494
64,526
28,055,130
20
Advances: Note
(f)
05/09/1988
1,127,868
1,127,868
21
Note
(g)
09/06/1988
2,580,000
2,580,000
22
Note
(h)
12/30/1988
8,712,308
8,712,308
23
Note
(i)
08/22/1989
2,880,000
2,880,000
24
Note
(j)
10/09/1990
4,200,000
4,200,000
25
Note
(k)
02/25/1992
3,300,000
3,300,000
26
Note
(l)
12/01/1993
1,518,000
1,518,000
27
SUBTOTAL
40,647,308
64,526
42,154,119
28
Midway Power LLC
29
Additional Paid in Capital
26,085,184
26,112,410
30
Undistributed Earnings
21,646,507
27,226
21,673,733
31
SUBTOTAL
4,438,677
27,226
4,438,677
42
Total Cost of Account 123.1 $
Total
48,859,887
42,609
50,082,345


FOOTNOTE DATA

(a) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1978
(b) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1954
(c) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1989
(d) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1930-32
(e) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 1954
(f) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 05/09/1988
(g) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 09/06/1988
(h) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 12/30/1988
(i) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 08/22/1989
(j) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 10/09/1990
(k) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 02/25/1992
(l) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 12/01/1993
(m) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 2008
(n) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(o) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(p) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(q) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(r) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(s) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND
(t) Concept: DateOfMaturityInvestmentsInSubsidiaryCompanies
Original value: DEMAND

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
MATERIALS AND SUPPLIES
  1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a); estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
  2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense clearing, if applicable.
Line No.
Account
(a)
Balance Beginning of Year
(b)
Balance End of Year
(c)
Department or Departments which Use Material
(d)
1
Fuel Stock (Account 151)
1,375,066
1,566,341
ELECTRIC
2
Fuel Stock Expenses Undistributed (Account 152)
3
Residuals and Extracted Products (Account 153)
4
Plant Materials and Operating Supplies (Account 154)
5
Assigned to - Construction (Estimated)
98,115,315
118,788,016
ALL
6
Assigned to - Operations and Maintenance
7
Production Plant (Estimated)
131,373,581
122,909,574
ALL
8
Transmission Plant (Estimated)
31,138,026
42,589,220
ALL
9
Distribution Plant (Estimated)
104,997,211
158,373,602
ALL
10
Regional Transmission and Market Operation Plant (Estimated)
11
Assigned to - Other (provide details in footnote)
12
TOTAL Account 154 (Enter Total of lines 5 thru 11)
365,624,133
442,660,412
13
Merchandise (Account 155)
14
Other Materials and Supplies (Account 156)
15
Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util)
16
Stores Expense Undistributed (Account 163)
ALL
17
18
19
20
TOTAL Materials and Supplies
366,999,199
444,226,753


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
SO2 Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
129,839
13,860
13,860
13,860
360,360
531,779
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
13,860
13,860
5
Returned by EPA
6
7
8
Purchases/Transfers:
9
10
11
12
13
14
15
Total
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
20.1
Allowances Used
12
12
20.2
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
129,827
13,860
13,860
13,860
374,220
545,627
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
199
199
199
199
9,751
10,547
37
Add: Withheld by EPA
398
398
38
Deduct: Returned by EPA
39
Cost of Sales
199
199
398
40
Balance-End of Year
199
199
199
9,950
10,547
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
17
5
22
45
Gains
17
5
22
46
Losses


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AllowanceInventory

Total ending balance of account 158.1 per this page does not agree to the corresponding balance sheet line item on page 110. Difference is due to approximately $395,755,701 in CO2 allowances issued by the California Air Resources Board (CARB) and approximately $430,000 in alternative fuel vehicle credits.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Allowances (Accounts 158.1 and 158.2)
  1. Report below the particulars (details) called for concerning allowances.
  2. Report all acquisitions of allowances at cost.
  3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts.
  4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k).
  5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40.
  6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances.
  7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts).
  8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of and identify associated companies.
  9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers.
  10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.
Current Year Year One Year Two Year Three Future Years Totals
Line No.
NOx Allowances Inventory (Account 158.1)
(a)
No.
(b)
Amt.
(c)
No.
(d)
Amt.
(e)
No.
(f)
Amt.
(g)
No.
(h)
Amt.
(i)
No.
(j)
Amt.
(k)
No.
(l)
Amt.
(m)
1
Balance-Beginning of Year
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
5
Returned by EPA
6
7
8
9
10
11
12
13
14
15
Total
16
17
Relinquished During Year:
18
Charges to Account 509
19
Other:
20
Allowances Used
20.1
20.2
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
30
31
Sales:
32
Net Sales Proceeds(Assoc. Co.)
33
Net Sales Proceeds (Other)
34
Gains
35
Losses
Allowances Withheld (Acct 158.2)
36
Balance-Beginning of Year
37
Add: Withheld by EPA
38
Deduct: Returned by EPA
39
Cost of Sales
40
Balance-End of Year
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
44
Net Sales Proceeds (Other)
45
Gains
46
Losses


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
EXTRAORDINARY PROPERTY LOSSES (Account 182.1)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfExtraordinaryPropertyLoss
Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).]
(a)
ExtraordinaryPropertyLossesNotYetRecognized
Total Amount of Loss
(b)
ExtraordinaryPropertyLossesRecognized
Losses Recognized During Year
(c)
ExtraordinaryPropertyLossesWrittenOffAccountCharged
Account Charged
(d)
ExtraordinaryPropertyLossesWrittenOff
Amount
(e)
ExtraordinaryPropertyLosses
Balance at End of Year
(f)
1
NONE
20 TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2)
WRITTEN OFF DURING YEAR
Line No.
DescriptionOfUnrecoveredPlantAndRegulatoryStudyCosts
Description of Unrecovered Plant and Regulatory Study Costs [Include in the description of costs, the date of COmmission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)]
(a)
UnrecoveredPlantAndRegulatoryStudyCostsNotYetRecognized
Total Amount of Charges
(b)
UnrecoveredPlantAndRegulatoryStudyCostsRecognized
Costs Recognized During Year
(c)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOffAccountCharged
Account Charged
(d)
UnrecoveredPlantAndRegulatoryStudyCostsWrittenOff
Amount
(e)
UnrecoveredPlantAndRegulatoryStudyCosts
Balance at End of Year
(f)
21
Santa Cruz 115kV Reinforcement
3,683,889
63,333
3,620,556
22
10/4/2016 (03/2016 to 12/2075)
23
DCPP Relicensing
16,403,494
2,050,437
14,353,057
24
01/01/2018 (01/2018 to 12/2025)
25
DCPP Canceled Orders
50,835,492
50,835,492
26
01/01/2018 (Pending 2020 GRC)
49
TOTAL
70,922,875
2,113,770
68,809,105


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Transmission Service and Generation Interconnection Study Costs
  1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies.
  2. List each study separately.
  3. In column (a) provide the name of the study.
  4. In column (b) report the cost incurred to perform the study at the end of period.
  5. In column (c) report the account charged with the cost of the study.
  6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
  7. In column (e) report the account credited with the reimbursement received for performing the study.
Line No.
DescriptionOfStudyPerformed
Description
(a)
StudyCostsIncurred
Costs Incurred During Period
(b)
StudyCostsAccountCharged
Account Charged
(c)
StudyCostsReimbursements
Reimbursements Received During the Period
(d)
StudyCostsAccountReimbursed
Account Credited With Reimbursement
(e)
1
Transmission Studies
2
(a)
(See details in foot notes)
2,610,739
2,353,572
20
Total
21
Generation Studies
22
(b)
(See details in foot notes)
1,120,039
2,034,585
39
Total
40 Grand Total


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

Order

Order Description

Balance 12/31/17

Cost Incurred

Reimbursements received

Balance 12/31/18

9715072

WL -(SIS)Interconnection Merced Irr Dist

 

 

(500.00)

(500.00)

9719582

WG Gradient Resources Project SIS

22,883.99

 

 

22,883.99

9719800

WAPA O'Neill Substation - System Impact

4,623.39

 

 

4,623.39

9719900

WG - BURNS&MCDONNELL-Cluster work

5,991.03

(473.44)

 

5,517.59

9722202

WG - C6 - Cluster 6 Phase 2

24,433.62

 

 

24,433.62

9724040

KMPUD Load Interconnection Study

(11,807.00)

 

 

(11,807.00)

9724300

Ntwrk Eval for Calpine 115kV Geysers Gen

(10,369.32)

 

 

(10,369.32)

9725002

WG - C8 - SM - Quail Creek Solar 1

127.91

 

 

127.91

9725844

CDWR BDCP Phase 2 sudy

703.14

 

 

703.14

9726740

WG - 2016 Reassessment Gen Interconn

(0.68)

 

 

(0.68)

9726940

WAPA - Cottonwood Olinda line work

106,088.91

 

 

106,088.91

9727720

SFPUC - Potrero Interconnection

179.06

 

 

179.06

9727980

LBNL Capacity Increase

4,653.80

 

 

4,653.80

9728340

SVP Breaker Replacement

(8,863.39)

 

 

(8,863.39)

9728360

Travis AFB Facility Study

(64,155.75)

 

 

(64,155.75)

9728526

Port of Stockton Load Increase

(21,889.59)

 

 

(21,889.59)

9728645

WG # MMA # Q720&Q1002

(0.02)

 

 

(0.02)

9729040

2016 Merced ID Load Interconnection Faci

(19,503.75)

 

(19,503.75)

(39,007.50)

9729280

LBNL Interconnection Capacity Increase

23,582.69

 

(23,583.00)

(0.31)

9729340

WG - 2017 Reassessment

301,644.22

 

(301,644.00)

0.22

9729546

WAPA SLTP

3,043.50

 

 

3,043.50

9729703

WG - C9P2 - Cluster 9 Phase 2

789,183.38

36,814.01

(826,010.60)

(13.21)

9729761

Port of Stockton FAS

(40,364.18)

 

 

(40,364.18)

9729808

WG - Cluster IR Review/SM for Protection

(0.20)

5,158.61

 

5,158.41

9729841

WG - C10P1 - Cluster 10 Phase 1

519,231.36

267,217.07

(786,448.44)

(0.01)

9729845

WG - C10 - SM - Project01

(104.94)

 

 

(104.94)

9729846

WG - C10 - SM - Project02

(127.98)

 

 

(127.98)

9729847

WG - C10 - SM - Project03

(128.64)

 

 

(128.64)

9729848

WG - C10 - SM - Project04

(242.05)

 

 

(242.05)

9729849

WG - C10 - SM - Project05

(155.86)

 

 

(155.86)

9729850

WG - C10 - SM - Project06

(257.93)

 

 

(257.93)

9729851

WG - C10 - SM - Project07

(197.01)

 

 

(197.01)

9729852

WG - C10 - SM - Project08

(247.86)

 

 

(247.86)

9729853

WG - C10 - SM - Project09

(192.47)

 

 

(192.47)

9729854

WG - C10 - SM - Project10

(237.51)

 

 

(237.51)

9729855

WG - C10 - SM - Project11

5,426.86

 

 

5,426.86

9729856

WG - C10 - SM - Project12

(134.78)

 

 

(134.78)

9729857

WG - C10 - SM - Project13

(112.86)

 

 

(112.86)

9729859

WG - C10 - SM - Project15

(186.00)

 

 

(186.00)

9729881

WG - C10 - SM - Project17

(226.49)

 

 

(226.49)

9729882

WG - C10 - SM - Project18

(145.56)

 

 

(145.56)

9729883

WG - C10 - SM - Project19

(124.42)

 

 

(124.42)

9729884

WG - C10 - SM - Project20

(237.94)

 

 

(237.94)

9729885

WG - C10 - SM - Project21

(5,962.76)

 

 

(5,962.76)

9729886

WG - C10 - SM - Project22

(170.12)

 

 

(170.12)

9729887

WG - C10 - SM - Project23

(144.19)

 

 

(144.19)

9729888

WG - C10 - SM - Project24

(133.48)

 

 

(133.48)

9729889

WG - C10 - SM - Project25

(151.47)

 

 

(151.47)

9729890

WG - C10 - SM - Project26

(249.28)

 

 

(249.28)

9729891

WG - C10 - SM - Project27

(197.01)

 

 

(197.01)

9729892

WG - C10 - SM - Project28

(271.86)

 

 

(271.86)

9729893

WG - C10 - SM - Project29

(264.84)

 

 

(264.84)

9729894

WG - C10 - SM - Project30

(112.09)

 

 

(112.09)

9729895

WG - C10 - SM - Project31

(220.00)

 

 

(220.00)

9729896

WG - C10 - SM - Project32

(220.33)

 

 

(220.33)

9729897

WG - C10 - SM - Project33

(101.95)

 

 

(101.95)

9729898

WG - C10 - SM - Project34

(79.06)

 

 

(79.06)

9729899

WG - C10 - SM - Project35

(147.21)

 

 

(147.21)

9729900

WG - C10 - SM - Project36

(269.40)

 

 

(269.40)

9729901

WG - C10 - SM - Project37

(177.25)

 

 

(177.25)

9729902

WG - C10 - SM - Project38

(258.96)

1,680.00

 

1,421.04

9729903

WG - C10 - SM - Project39

(70.70)

 

 

(70.70)

9729904

WG - C10 - SM - Project40

(163.29)

 

 

(163.29)

9729905

WG - C10 - SM - Project41

(195.08)

 

 

(195.08)

9729906

WG - C10 - SM - Project42

(122.16)

 

 

(122.16)

9729907

WG - C10 - SM - Project43

(309.21)

 

 

(309.21)

9729908

WG - C10 - SM - Project44

(163.08)

 

 

(163.08)

9729909

WG - C10 - SM - Project45

(242.71)

 

 

(242.71)

9729910

WG - C10 - SM - Project46

(292.32)

 

 

(292.32)

9729911

WG - C10 - SM - Project47

(438.55)

 

 

(438.55)

9729912

WG - C10 - SM - Project48

(339.34)

 

 

(339.34)

9729913

WG - C10 - SM - Project49

(265.06)

 

 

(265.06)

9729914

WG - C10 - SM - Project50

(79.39)

 

 

(79.39)

9729960

WG - C10 - SM - Project51

(9.36)

 

 

(9.36)

9729961

WG - C10 - SM - Project52

(134.78)

 

 

(134.78)

9729962

WG - C10 - SM - Project53

(102.07)

 

 

(102.07)

9729963

CAISO ISP Panoche

2,875.63

 

(3,136.48)

(260.85)

9730243

SFPUC - Potrero Interconnection

(100,813.68)

2,399.32

100,813.60

2,399.24

9730361

SVP Breaker Replacement Facility Study

8,269.68

 

(8,269.68)

-

9730681

WG - ISP - Porthos

 

1,680.00

 

1,680.00

9730823

WAPA Lemoore NAS

8,738.92

11,027.90

 

19,766.82

9732360

WG # Cluster 11 Phase 1

 

742,359.93

 

742,359.93

9707780

CP-Martin 115/60 kV Upgrade Project

379.02

1,343.45

 

1,722.47

9713955

WL - Tesla Tracy 230kV Line 1 Reloc-FAS

13,215.50

 

 

13,215.50

9722206

Trans Bay Cable Quick Start Study

3,596.35

1,667.86

 

5,264.21

9717187

WL - CA HiSpeed Train Interconnect Study

26,847.97

8,299.32

(11,297.12)

23,850.17

9714755

WL - KMPUD-IFAS

63,553.10

 

 

63,553.10

9731302

Swan Lake Affected Sys. Study

11,470.57

70,774.74

 

82,245.31

9731780

WG - 2018 Reassessment

 

387,072.56

 

387,072.56

9732200

WG # ISP-South Belridge Expansion

 

27,452.87

 

27,452.87

9732401

WG - C11 - SM - Project 01

 

5,691.89

(5,754.78)

(62.89)

9732402

WG - C11 - SM - Project 02

 

7,889.17

(7,952.05)

(62.88)

9732404

WG - C11 - SM - Project 04

 

6,231.20

(4,294.01)

1,937.19

9732405

WG - C11 - SM - Project 05

 

7,762.29

(7,825.18)

(62.89)

9732406

WG - C11 - SM - Project 06

 

7,200.50

(7,263.39)

(62.89)

9732407

WG - C11 - SM - Project 07

 

5,711.86

(5,774.75)

(62.89)

9732408

WG - C11 - SM - Project 08

 

8,178.59

(8,602.78)

(424.19)

9732409

WG - C11 - SM - Project 09

 

4,202.96

(4,265.85)

(62.89)

9732410

WG - C11 - SM - Project 10

 

5,437.91

(5,500.81)

(62.90)

9732411

WG - C11 - SM - Project 11

 

7,048.98

(6,436.84)

612.14

9732412

WG - C11 - SM - Project 12

 

7,057.66

(5,120.55)

1,937.11

9732413

WG - C11 - SM - Project 13

 

8,273.24

(8,336.13)

(62.89)

9732414

WG - C11 - SM - Project 14

 

5,468.32

(5,531.21)

(62.89)

9732415

WG - C11 - SM - Project 15

 

5,019.49

(5,082.38)

(62.89)

9732416

WG - C11 - SM - Project 16

 

4,546.60

(4,609.49)

(62.89)

9732417

WG - C11 - SM - Project 17

 

4,099.84

(4,162.74)

(62.90)

9732418

WG - C11 - SM - Project 18

 

4,955.96

(4,974.65)

(18.69)

9732419

WG - C11 - SM - Project 19

 

4,690.86

(4,753.75)

(62.89)

9732420

WG - C11 - SM - Project 20

 

6,610.86

(6,673.75)

(62.89)

9732421

WG - C11 - SM - Project 21

 

5,122.96

(5,185.85)

(62.89)

9732422

WG - C11 - SM - Project 22

 

5,897.47

(5,960.36)

(62.89)

9732423

WG - C11 - SM - Project 23

 

4,250.08

(4,312.97)

(62.89)

9732424

WG - C11 - SM - Project 24

 

5,274.03

(5,336.92)

(62.89)

9732425

WG - C11 - SM - Project 25

 

5,870.92

(3,933.81)

1,937.11

9732426

WG - C11 - SM - Project 26

 

4,786.84

(5,030.36)

(243.52)

9732427

WG - C11 - SM - Project 27

 

3,434.70

(3,497.60)

(62.90)

9732428

WG - C11 - SM - Project 28

 

6,053.19

(6,116.08)

(62.89)

9732429

WG - C11 - SM - Project 29

 

4,847.87

(4,910.76)

(62.89)

9732430

WG - C11 - SM - Project 30

 

4,991.41

(5,054.30)

(62.89)

9732431

WG - C11 - SM - Project 31

 

9,373.22

(9,616.74)

(243.52)

9732432

WG - C11 - SM - Project 32

 

4,304.22

(4,367.11)

(62.89)

9732433

WG - C11 - SM - Project 33

 

4,111.53

(4,174.43)

(62.90)

9732434

WG - C11 - SM - Project 34

 

4,084.00

(4,146.89)

(62.89)

9732435

WG - C11 - SM - Project 35

 

5,656.58

(5,900.09)

(243.51)

9732436

WG - C11 - SM - Project 36

 

4,675.96

(4,738.85)

(62.89)

9732437

WG - C11 - SM - Project 37

 

6,976.77

(7,039.66)

(62.89)

9732438

WG - C11 - SM - Project 38

 

6,851.40

(6,914.29)

(62.89)

9732439

WG - C11 - SM - Project 39

 

7,411.34

(7,474.23)

(62.89)

9732440

WG - C11 - SM - Project 40

 

5,254.08

(5,317.86)

(63.78)

9732441

WG - C11 - SM - Project 41

 

5,989.28

(5,292.87)

696.41

9732442

WG - C11 - SM - Project 42

 

7,262.53

(7,325.42)

(62.89)

9732443

WG - C11 - SM - Project 43

 

5,624.61

(5,687.49)

(62.88)

9732444

WG - C11 - SM - Project 44

 

6,546.73

(6,609.62)

(62.89)

9732445

WG - C11 - SM - Project 45

 

6,783.25

(4,846.14)

1,937.11

9732447

WG - C11 - SM - Project 47

 

4,935.89

(4,785.48)

150.41

9732448

WG - C11 - SM - Project 48

 

5,649.91

(4,712.80)

937.11

9732449

WG - C11 - SM - Project 49

 

5,897.73

(5,960.62)

(62.89)

9732450

WG - C11 - SM - Project 50

 

5,095.82

(5,158.71)

(62.89)

9732451

WG - C11 - SM - Project 51

 

4,857.73

(4,920.62)

(62.89)

9732452

WG - C11 - SM - Project 52

 

6,361.04

(6,423.93)

(62.89)

9732453

WG - C11 - SM - Project 53

 

5,973.87

(6,398.06)

(424.19)

9732454

WG - C11 - SM - Project 54

 

6,197.48

(6,260.37)

(62.89)

9732455

WG - C11 - SM - Project 55

 

3,599.69

(3,662.58)

(62.89)

9732560

WG - C11 - SM - Project 100

 

1,015.80

(1,058.13)

(42.33)

9732561

WG - C11 - SM - Project 56

 

5,190.29

(5,208.47)

(18.18)

9732562

WG - C11 - SM - Project 57

 

3,309.69

(3,372.58)

(62.89)

9732563

WG - C11 - SM - Project 58

 

6,229.46

(6,292.35)

(62.89)

9732564

WG - C11 - SM - Project 59

 

5,121.81

(5,184.70)

(62.89)

9732565

WG - C11 - SM - Project 60

 

10,493.02

(9,595.92)

897.10

9732566

WG - C11 - SM - Project 61

 

5,515.06

(5,577.94)

(62.88)

9732567

WG - C11 - SM - Project 62

 

6,324.27

(6,387.16)

(62.89)

9732568

WG - C11 - SM - Project 63

 

6,106.39

(6,169.28)

(62.89)

9732569

WG - C11 - SM - Project 64

 

2,000.00

 

2,000.00

9732570

WG - C11 - SM - Project 65

 

5,928.55

(5,991.44)

(62.89)

9732571

WG - C11 - SM - Project 66

 

8,104.68

(8,167.57)

(62.89)

9732572

WG - C11 - SM - Project 67

 

4,395.40

(4,458.29)

(62.89)

9732573

WG - C11 - SM - Project 68

 

6,727.56

(6,790.45)

(62.89)

9732574

WG - C11 - SM - Project 69

 

3,841.73

(3,145.32)

696.41

9732575

WG - C11 - SM - Project 70

 

5,008.19

(5,071.08)

(62.89)

9732576

WG - C11 - SM - Project 71

 

8,716.48

(8,779.37)

(62.89)

9732577

WG - C11 - SM - Project 72

 

5,864.44

(3,927.33)

1,937.11

9732578

WG - C11 - SM - Project 73

 

4,569.57

(4,632.46)

(62.89)

9732579

WG - C11 - SM - Project 74

 

7,831.40

(7,894.29)

(62.89)

9732580

WG - C11 - SM - Project 75

 

7,025.13

(7,088.02)

(62.89)

9732581

WG - C11 - SM - Project 76

 

143.54

 

143.54

9732583

WG - C11 - SM - Project 78

 

1,435.71

(1,478.04)

(42.33)

9732584

WG - C11 - SM - Project 79

 

4,587.40

(4,650.29)

(62.89)

9732586

WG - C11 - SM - Project 81

 

4,682.65

(3,916.84)

765.81

9732587

WG - C11 - SM - Project 82

 

7,937.26

(8,000.15)

(62.89)

9732588

WG - C11 - SM - Project 83

 

7,876.23

(7,939.12)

(62.89)

9732589

WG - C11 - SM - Project 84

 

5,615.59

(5,678.48)

(62.89)

9732590

WG - C11 - SM - Project 85

 

5,002.45

(5,065.34)

(62.89)

9732591

WG - C11 - SM - Project 86

 

5,277.50

(5,340.39)

(62.89)

9732592

WG - C11 - SM - Project 87

 

7,023.39

(7,086.28)

(62.89)

9732593

WG - C11 - SM - Project 88

 

7,572.21

(5,635.10)

1,937.11

9732594

WG - C11 - SM - Project 89

 

4,075.97

(4,138.86)

(62.89)

9732595

WG - C11 - SM - Project 90

 

240.00

(282.33)

(42.33)

9732681

WG # Cluster 10 Phase 2

 

559,394.02

 

559,394.02

 

Total Transmission

1,657,857.38

2,610,739.35

(2,353,571.80)

1,915,024.93

 

(b) Concept: DescriptionOfStudyPerformed

Order

Order Description

Balance 12/31/17

Cost Incurred

Reimbursements received

Balance 12/31/18

9724683

TO-Green Ridge Repowering Facilities Sty

7,404.53

 

(7,404.53)

-

9725281

Estrella Substation - Facilities Study

(677.55)

 

 

(677.55)

9727121

WDT Ripon Independent Study Process

(55,736.76)

 

55,736.76

-

9727122

WDT Ripon FCDS Full Capac Deliver Status

(13,295.97)

 

13,295.97

-

9727181

WDT Cabrillo Wind Energy Indep Study

7,348.06

 

(7,348.06)

-

9727183

R21 Verwey-Hanford Dairy Digestr Det Sty

568.76

 

(568.76)

-

9727300

WDT-HZI-Waste Conn Fac SLO 4-16 Indep Sy

1,446.94

 

(1,446.94)

-

9728500

WDT - Apple Hill ES 1 Independent Study

(58,600.74)

79.71

58,521.03

-

9728501

WDT - Apple Hill ES 2 Independent Study

(57,902.83)

79.71

57,823.12

-

9728502

WDT - Apple Hill ES 1 Deliverability Sty

1,686.69

22,311.75

(23,998.44)

-

9728503

WDT - Apple Hill ES 2 Deliverability Sty

(3,138.13)

22,311.75

(19,173.62)

-

9728663

WDT - Poco Power - Fast Track Study

1,978.90

 

(1,978.90)

-

9728701

WDT - 50001 SCWA North/South Cluster 10

(48,704.94)

2,543.26

46,161.68

-

9728800

R21 David Tevelde Dairy Digester Det Sty

(1,335.62)

 

1,335.62

-

9728963

R21 Target Corp Shafter Detailed Study

(5,991.83)

 

5,991.83

-

9729141

WDT - HZIU Kompogas SLO - ISP

(3,429.56)

 

3,429.56

-

9729180

R21 Charleston East 344360 NEM 2 Det Sty

(1,796.13)

 

1,796.13

-

9729240

Castroville Energy Stg 5MW Indepent Sty

(3,074.77)

 

3,074.77

-

9729360

WDT - SEPV Cuyama - Fast Track Study

(16.37)

 

16.37

-

9729460

WDT - Sirius Ph 3 Fast Track Study

1,139.84

 

(1,139.84)

-

9729480

R21 Maddox Dairy Ph1 Enos 347251 Det Sty

(4,246.46)

 

4,246.46

-

9729481

WDT - Madera 2 Fast Tack Study

1,111.41

 

(1,111.41)

-

9729482

WDT - Kettleman 1 Fast Track Study

(396.71)

 

396.71

-

9729520

R21 Berrenda Mesa Water 352031 Det Study

(45,502.87)

3,101.62

42,401.25

-

9729522

R21Beldrige Wtr Stor 352165 NEM2 Det Sty

1,110.28

2,128.90

 

3,239.18

9729523

R21 - SCRWA - ENOS 318636 - Detailed Sty

154.35

 

(154.35)

-

9729524

WDT - SEPV Cuyama Supplemental Review

(643.56)

 

643.56

-

9729621

QF 19C010 Humboldt Redwood Facility Sty

(6,278.37)

 

6,278.37

-

9729681

SPI Quincy - Facilities Study

(5,553.31)

 

5,553.31

-

9729700

SPI Sonora - Facilities Study

(5,503.40)

 

5,503.40

-

9729701

WDT - NortBelridge Comm Solar Fast Track

3,152.22

 

(3,152.22)

-

9729704

WDT - West Paso Community Solar Fast Trk

(396.71)

 

396.71

-

9729760

WDT - SEPV Cuyama System Impact Study

(4,004.83)

 

4,004.83

-

9729800

WDT - Cadet Community Solar Fast Track

999.25

 

(999.25)

-

9729801

WDT - Midway-Sunset Comm Solar Fast Trk

(17.23)

 

17.23

-

9729804

R21 Premier Int Hold 361723 NEM2 Det Sty

(53,617.87)

168.41

53,449.46

-

9729805

WDT - Nacimiento Interc Study 2017 Indep

2,599.12

7,176.64

(9,775.76)

-

9729806

WDT - Chevron USA Prod Co ISP

(55,768.92)

25,503.83

 

(30,265.09)

9729807

WDT - Dalena Farms Cluster Study

(41,293.57)

 

41,293.57

-

9729810

1453-WD BUCCANEER System Impact Study

(6,532.65)

 

6,532.65

-

9729844

WDT - SEPV Kings - Fast Track

(165.37)

 

165.37

-

9729861

WDT-1484-WD-North Belridge Com - Sup Rev

324.89

 

(324.89)

-

9729920

1452-WD Madera 2 - Independent Study

(9,618.87)

 

9,618.87

-

9729921

Shiloh I Wind Project Facilities Study

(1,813.36)

22,049.91

 

20,236.55

9729923

Exchequer RAS - CAISO Post COD

(202.13)

4,498.16

 

4,296.03

9729940

R21 Cache Creek Casino 366552 Det Study

(55,051.42)

 

55,051.42

-

9729942

R21 Kern Oil Refining (98110) Detail Sty

(5,899.35)

 

5,899.35

-

9729980

MMA - Q1158 Slate - ISO 51731

1,901.45

3,898.78

 

5,800.23

9729981

MMA-Q1036 Mustang 2-Gen-Tie-ISO 51601

1,748.70

 

 

1,748.70

9730000

MMA - Q1011 GHS Project - ISO 51541

2,861.30

720.00

(3,581.30)

-

9730003

WDT - Midway Sunset Comm Solar Supp Rev

(1,163.82)

 

1,163.82

-

9730060

MMA - QF Santa Clara Wind - 51155

2,791.43

10,659.21

 

13,450.64

9730061

MMA - Q1096 & QF Altamont Midway - 51156

2,059.42

10,387.56

 

12,446.98

9730062

MMA - QF Forebay Wind - 51154

1,599.42

13,303.29

 

14,902.71

9730065

Q877 California Flats - Roadway PEIE

(572,623.38)

56,043.47

 

(516,579.91)

9730066

1499-WD - Cadet Community Supp Review

(178.36)

 

178.36

-

9730068

1419-RD Sandridge Ptnrs NEMA2 Det Study

(3,184.01)

 

3,184.01

-

9730120

City of Wasco 370604 RESBCT Detailed Sty

(6,663.16)

 

6,663.16

-

9730121

WDT - Kent Solar Fast Track Study

672.78

 

(672.78)

-

9730123

R21-Mariposa Biomass Prj-Detailed Study

(6,384.40)

7,411.56

(1,027.16)

-

9730180

MMA - Q1011 GHS Project-Gen-Tie - 51541

85.85

 

(85.85)

-

9730181

MMA - QF Oroville Cogeneration - 51158

3,721.05

15,343.36

(19,064.41)

-

9730182

WDT - IP Cabernet - Fast Track

879.69

 

(879.69)

-

9730220

R21 George DeBoer Q-1432-RD Detailed Sty

(6,671.38)

 

6,671.38

-

9730221

R21 Henry Miller Q-1433-RD Detailed Sty

(6,414.58)

 

6,414.58

-

9730242

MMA - Q653F SP PVUSA - BESS-ISO 60192-C

1,254.92

2,130.61

 

3,385.53

9730244

R21 Rijlaarsdam NEMA 2 1483-RD (Det Sty)

(6,280.15)

673.66

5,606.49

-

9730280

MMA-Q1028&29 Ltl Bear Solar1&2-ISO 51587

460.00

 

(460.00)

-

9730281

WDT - CA-17-0018 SB43 MAHAL (FT)

1,204.71

 

(1,204.71)

-

9730304

1510-WD Semperviren 2, Shadelands - SR

235.43

 

(235.43)

-

9730305

WDT IP Malbec - FT

(19.39)

 

19.39

-

9730320

R21 1458-RD State Center Comm. Detailed

(5,197.90)

 

5,197.90

-

9730340

WDT - Korbel Power (ISP)

2,848.46

2,486.49

(5,334.95)

-

9730360

Kingsburg Cogen - Facility Study

1,493.72

 

 

1,493.72

9730382

WDT-Eurus Energy-Facility Mods Study

(20,499.84)

 

20,499.84

-

9730420

1469-RD BELRIDGE WATER/Detailed

(8,779.68)

542.86

 

(8,236.82)

9730421

1513-RD Sandridge Partners/Detailed

(7,015.09)

 

7,015.09

-

9730441

R21 - Shasta Storage 1/Detailed

(58,612.30)

8,118.89

50,493.41

-

9730481

R21 D ARRIGO BROS CO OF CALIF/Detailed

(7,366.09)

5,091.62

2,274.47

-

9730500

Kent Solar, LLC (1521-WD) - ISP

(797.93)

 

797.93

-

9730540

WDT Small World Trading - FT

(137.67)

482.96

(345.29)

-

9730580

WDT Semperviren 3 - FT

(261.53)

 

261.53

-

9730581

R21 Avalon Dairy Digester/Detailed

(8,372.10)

84.18

8,287.92

-

9730600

R21 The Wine Group LLC/Detailed

(10,000.00)

 

10,000.00

-

9730620

WDT Peterson Road 2/FT

1,996.99

 

(1,996.99)

-

9730640

WDT - 50003 SCWA R4 - Independent Study

(8,206.35)

2,062.38

6,143.97

-

9730660

WDT - CA-17-0097 SB43 Arco - ISP

1,226.45

 

 

1,226.45

9730662

R21 - Bear Creek - EDMUD - Detailed Stdy

(7,313.18)

1,742.15

 

(5,571.03)

9730664

WDT-CA-17-0101 SB43 Devils Den-Fst Trk

1,870.10

637.37

 

2,507.47

9730665

WDT-CA-17-0102 SB43 Gates-ISP

(7,157.80)

5,317.41

 

(1,840.39)

9730666

WDT-CA-17-0106 SB43 Coalinga 1-Fst Trk

(205.19)

 

205.19

-

9730667

WDT-CA-17-0122 SB43 Coalinga 2-Fst Trk

(349.19)

 

349.19

-

9730672

WDT - CA-17-0018 SB43 Mahal - Sup Rev

(2,181.98)

 

2,181.98

-

9730740

CA Department of Corrections #387295/Det

(10,000.00)

4,024.30

 

(5,975.70)

9730743

WDT CA-17-0100 SB43 Derrick/ISP

(9,261.82)

11,093.91

 

1,832.09

9730744

WDT - American Canyon Solar A/FT

337.05

 

(337.05)

-

9730745

WDT - American Canyon Solar B/FT

(714.84)

 

714.84

-

9730746

WDT - American Canyon Solar C/FT

487.28

 

(487.28)

-

9730760

R21 EBMUD Enos (387729) RESBCT/Detailed

(54,657.88)

848.29

 

(53,809.59)

9730784

WDT SEPV American Canyon/FT

206.98

 

 

206.98

9730785

WDT Palm Drive Solar A/FT

57.14

 

(57.14)

-

9730786

WDT Palm Drive Solar B/FT

301.72

 

(301.72)

-

9730800

R21 - Bangor Solar - 1402-RD - Det Stdy

(10,000.00)

510.50

 

(9,489.50)

9730820

WDT-CA-17-0090 SB43 Dulgarian/FT

233.16

 

 

233.16

9730822

WDT - Merced 2/FT

1,438.38

 

(1,438.38)

-

9730840

WDT - IP Cabernet_08_2017/FT

(217.78)

84.18

133.60

-

9730861

R21 - City Count of SF (Enos 390303)/Det

(7,995.02)

1,945.79

 

(6,049.23)

9730862

1529-RD City of Paso Robles/Detailed

(6,924.19)

252.59

 

(6,671.60)

9730880

WDT - DRES Quarry 2.3/FT

118.85

39.83

 

158.68

9730881

WDT - IP Merlot 1/FT

146.85

 

(146.85)

-

9730882

WDT - IP Merlot 2/FT

434.79

 

(434.79)

-

9730883

WDT - IP Merlot 3/FT

913.24

 

(913.24)

-

9730920

WDT-SR Sovereign Energy Semperviren 3

(2,066.74)

 

2,066.74

-

9730940

R21-Calcom Solar-Western Sky Dairy-DS

(849.72)

 

 

(849.72)

9730941

R21-OpTerra-S K F Sanitation District-DS

(7,099.86)

 

7,099.86

-

9730961

WDT - FT - San Rafael Airport Unit No. 2

690.01

425.39

(1,115.40)

-

9730962

WDT - ISP - Intersect Power - IP Porthos

(67,790.89)

240.00

67,550.89

-

9730963

WDT - FT - ZGlobal - Eagle 2 Solar

1,552.47

 

 

1,552.47

9730964

WDT - FT - Morris 385 LLC - Morris 385

1,537.23

1,139.98

 

2,677.21

9730966

WDT - FT - El Pomar Parners - El Pomar

830.99

 

 

830.99

9731000

WDT-SR 1561 American Canyon Solar A

(1,344.65)

 

1,344.65

-

9731002

WDT - SR - 1562 American Canyon Solar B

(1,779.25)

 

1,779.25

-

9731003

WDT - SR - 1563 American Canyon Solar C

(910.09)

 

910.09

-

9731020

R21-DS-MaasEn. Lakeside Energy Dairy Dig

(9,545.26)

 

9,545.26

-

9731040

WDT-SR-Rival Power-Peterson Road 2

532.20

956.05

(1,488.25)

-

9731060

R21 - DS - Chowchilla Dairy Power

(10,000.00)

 

 

(10,000.00)

9731061

WDT-FT-ET Solar - Midway Towers Comm Sol

(398.62)

2,104.04

 

1,705.42

9731062

WDT-FT-ET Solar - East Bay Community Sol

(420.55)

2,679.53

 

2,258.98

9731063

R21-DS-Sandridge Partners Etal-NEMA

(9,356.43)

3,738.03

5,618.40

-

9731080

MMA - QF Altamont Frick - ISO 51135-QM

562.14

 

(562.14)

-

9731081

WDT-SR-RenewableProp-Palm Drive Solar A

(1,316.47)

 

1,316.47

-

9731082

WDT-SR-RenewableProp-Palm Drive Solar B

(1,203.88)

 

1,203.88

-

9731120

MMA - Q965 Java Solar - ISO 51436

1,279.09

3,616.07

(4,895.16)

-

9731181

WDT-FT-CED White River 2 Battery Storage

292.10

 

(292.10)

-

9731182

R21 - Musco Olive Biom Gen - Fac Study

(7,870.82)

3,141.90

 

(4,728.92)

9731183

R21-DS-FoundationWindpower-Mann Packing

(8,222.45)

9,204.27

(981.82)

-

9731187

WDT - FT - ZGlobal - Merced 2

(1,000.00)

 

1,000.00

-

9731201

WDT - SR - IP Portfolio - IP Cabernet

(1,719.39)

79.71

1,639.68

-

9731202

WDT - SR - IP Portfolio - IP Merlot 1

(1,747.53)

163.91

1,583.62

-

9731203

WDT - SR - IP Portfolio - IP Merlot 2

(1,747.53)

203.76

1,543.77

-

9731204

WDT - SR - IP Portfolio - IP Merlot 3

(1,747.53)

203.76

1,543.77

-

9731205

WDT - SR - El Pomar Partners - El Pomar

(837.91)

626.82

 

(211.09)

9731206

WDT-SR-ForeFront Power-Ava Elizabeth

(1,360.63)

159.39

1,201.24

-

9731207

WDT-SR-ForeFront Power-Forefront C2

(841.60)

756.40

85.20

-

9731208

WDT-SR-ForeFront Power-Dulgarian

(876.35)

626.08

 

(250.27)

9731209

WDT - SR - San Rafael Airport Unit #2

(1,454.64)

1,386.22

68.42

-

9731210

WDT - FT - Solar Electric SEPV Cuyama 2

310.23

 

 

310.23

9731211

WDT - SR - Green Light - Eagle 2 Solar

(710.62)

956.05

 

245.43

9731280

R21-DS-BNB Renewable-Campbell Soup Supp

(9,660.92)

14,991.70

 

5,330.78

9731281

R21-DS-Renewable Solar-Danell Brothers

(8,346.32)

1,663.86

 

(6,682.46)

9731283

WDT - FT - SFPUC - Burton High School PV

(86.43)

79.70

6.73

-

9731287

R21-DIS-Forefront-CDCR-1569-RD

(10,000.00)

6,824.06

 

(3,175.94)

9731300

WDT-SR-Forefront Power-Mouren Farming

(974.16)

1,532.37

 

558.21

9731320

WDT - FT - EPRI - SVUSD Bus Barn Storage

524.47

3,801.86

 

4,326.33

9731340

R21 - DIS - West Biofuels - SunWest Bio

(9,622.20)

7,703.81

 

(1,918.39)

9731341

R21 - DIS - Syn Tech - Lisa Boone Harris

(10,000.00)

5,024.36

 

(4,975.64)

9731360

WDT-SIS-Solar Electric-SEPV Cuyama 2

(9,736.46)

6,182.86

 

(3,553.60)

9731380

R21-DIS-E&J Gallo Winery-Asti Pond Solar

 

3,187.55

(10,000.00)

(6,812.45)

9731381

R21-DIS-SunPower-EBMUD RESBCT

 

13,964.40

(55,000.00)

(41,035.60)

9731382

WDT-Forefront Power-Pistachio Road

(9,491.39)

4,299.55

5,191.84

-

9731383

R21-DIS-Maas Energy-Lakeshore Dairy Dig

(10,000.00)

2,706.73

 

(7,293.27)

9731480

WDT - FT - REP Energy - VGES 1

 

1,931.96

(1,931.96)

-

9731481

WDT - FT - REP Energy - VGES 2

 

1,931.96

(1,931.96)

-

9731482

WDT - SIS - Rival Power Peterson Road 2

(10,000.00)

4,157.48

 

(5,842.52)

9731484

R21 - DIS - JKB Energy-Trinitas Fund II

(9,491.39)

7,421.36

 

(2,070.03)

9731502

MMA-Q744 Redwood Solar (Phs4)-ISO 50857

44.05

960.00

(1,004.05)

-

9731503

R21-DIS-Concentric-South County Packing

(10,000.00)

11,099.38

 

1,099.38

9731504

R21-DIS-ARC Alternatives-City of Lincoln

(10,000.00)

966.79

 

(9,033.21)

9731507

WDT-FT-REP Energy-DRES Quarry 2.4

 

931.29

(1,000.00)

(68.71)

9731510

WDT-FT-Renewable Prop-Palm Drive Solar C

 

2,762.55

(1,000.00)

1,762.55

9731511

WDT-SR-ET Capital-Midway Towers Comm

 

 

(2,500.00)

(2,500.00)

9731517

WDT-SR-ET Capital, Inc. East Bay Com Sol

 

 

(2,500.00)

(2,500.00)

9731519

WDT-ISP-Calbio Energy-Bar20 Dairy Biogas

(10,000.00)

12,627.57

 

2,627.57

9731582

R21 - DIS - NRG - Calmat Co. Q#: 1593-RD

(10,000.00)

5,195.50

4,804.50

-

9731620

WDT-ISP-Calbio Energy-MaddoxDairyBiogas

 

5,702.06

(10,000.00)

(4,297.94)

9731621

WDT-ISP-Calbio Energy-Double Diamond

 

1,586.22

(10,000.00)

(8,413.78)

9731622

WDT - FT - Forefront Power - Rocha

 

873.01

(873.01)

-

9731623

MMA - Q1106 Fountain Wind - ISO 51770

 

637.71

(637.71)

-

9731624

R21-DIS--SunPower-West Valley Mission Co

 

3,409.23

(10,000.00)

(6,590.77)

9731626

R21-DIS-FirestoneWalker-FirestoneBrewery

 

4,351.51

(4,351.51)

-

9731640

WDT-SIS-Green Light Energy-Eagle 2 Solar

 

6,233.09

(10,000.00)

(3,766.91)

9731680

WDT-FT - DG California Solar-Lodi Solar

 

1,113.51

(1,000.00)

113.51

9731681

WDT-FT-DG California Solar-MendocinoSola

 

1,866.22

(1,866.22)

-

9731682

R21-DIS-DG Calif Solar, DPIF CA 6 Fresno

 

5,868.11

(10,000.00)

(4,131.89)

9731700

MMA - Q1141 Alamo Springs - ISO 51745

 

516.20

(516.20)

-

9731701

MMA - Q1157 Alamo Springs 2 - ISO 51708

 

200.45

(200.45)

-

9731702

WDT-ISP-Forefront Power-Nachtigall

 

2,228.73

(10,000.00)

(7,771.27)

9731703

WDT-ISP-Forefront Power-Terry

 

6,101.64

(6,101.64)

-

9731720

R21-DIS-ARC Alternatives-County of Kern

 

850.74

(10,000.00)

(9,149.26)

9731722

WDT-SR-Sonoma School-SVUSD Bus Barn Stor

 

1,449.01

(2,500.00)

(1,050.99)

9731723

WDT-Wireless Sur-Cenergy-NLH1 Solar-0102

 

1,089.84

(900.00)

189.84

9731724

WDT-ISP-Forefront Power-Broadman

 

4,047.67

(10,000.00)

(5,952.33)

9731740

R21-DIS-Forefront-CA Dept of Corr 23100

 

7,993.20

(10,000.00)

(2,006.80)

9731741

R21-DIS-Forefront-CA Dept of Corr 23104

 

2,815.05

(58,000.00)

(55,184.95)

9731742

R21-DIS-Forefront-CA Dept of Corr 23102

 

2,334.43

(56,000.00)

(53,665.57)

9731760

WDT-ISP-Forefront-Dulgarian (1589-WD)

 

5,220.21

(5,220.21)

-

9731761

WDT-ISP-Forefront-Forefront C2 (1587-WD)

 

4,431.53

(4,431.53)

-

9731762

WDT-ISP-Forefront-Ava Elizabeth 1586-WD

 

3,502.33

(3,502.33)

-

9731839

WDT - C9P2 - FCDS - Strauss Wind Energy

 

12,107.74

(12,107.74)

-

9731840

R21-DIS-Newcomb-City of Fresno(App22373)

 

4,120.71

(72,000.00)

(67,879.29)

9731841

WDT-EIT-Forefront-1584-WD Mouren Farming

 

4,754.01

(10,000.00)

(5,245.99)

9731842

MMA - Q705 - Frontier Solar - ISO 4411

 

964.33

(964.33)

-

9731880

MMA - Q877-CA Flats Solar 150-ISO 51211

 

1,925.53

(1,925.53)

-

9731881

R21-DIS-BloomEnergy-KeysightTechnologies

 

4,879.90

(10,000.00)

(5,120.10)

9731920

WDT-ISP-CEDWhiteRiverSolar2-WhiteRiver2

 

4,707.94

(10,000.00)

(5,292.06)

9731921

MMA - Collins Pine Repower - ISO 51161

 

9,732.02

 

9,732.02

9731960

WDT-SR-RenewProp-1758WD-PalmDriveSolarC

 

2,228.46

(2,500.00)

(271.54)

9731980

WDT-FT-OHR Energy-RuAnn Dairy Dig BioMAT

 

1,123.63

(1,123.63)

-

9731981

WDT-FT-Apex Energy/ZGlobal-Jade Solar

 

492.17

(1,000.00)

(507.83)

9732000

R21-DIS-SiliconVallCleanWater-12kVSwitch

 

7,313.96

(10,000.00)

(2,686.04)

9732001

WDT-FT-RenewProp-Silveira Ranch Solar C

 

1,434.17

(1,000.00)

434.17

9732002

WDT-FT-RenewProp-Silveira Ranch Solar D

 

1,604.34

(1,000.00)

604.34

9732003

MMA - Thermalito Powerplant - ISO 51162

 

28,978.38

 

28,978.38

9732020

WDT-FT-RenewProp-Silveira Ranch Solar A

 

1,814.76

(1,000.00)

814.76

9732021

WDT-FT-RenewProp-Silveira Ranch Solar B

 

1,944.67

(1,000.00)

944.67

9732022

WDT-FT - EnSync, Inc - 385 Morris

 

362.35

(362.35)

-

9732060

WDT-SR: Forefront Power-Rocha-1783-WD

 

1,768.39

(2,500.00)

(731.61)

9732080

WDT-ISP-YubaCityCogen-WaltonEnergyReliCe

 

1,714.74

(100,500.00)

(98,785.26)

9732081

WDT-SR: Pathion, Inc. - 1808-WD VGES 1

 

1,754.77

(1,754.77)

-

9732082

WDT-SR: Pathion, Inc. - 1809-WD VGES 2

 

2,116.36

(2,116.36)

-

9732100

WDT-ISP: PG&E CoyoteValleyEnergyStorage

 

14,854.92

 

14,854.92

9732121

R21-DIS-Forefront- UCSantaCruz App 23113

 

3,092.36

(10,000.00)

(6,907.64)

9732122

WDT-FT: Forefront Power - Kern Sunset

 

246.15

(1,000.00)

(753.85)

9732123

WDT-FT: Forefront Power - Highway 43

 

2,189.96

(1,000.00)

1,189.96

9732124

WDT-FT: Forefront Power - Beard

 

120.78

(1,000.00)

(879.22)

9732180

WDT-FCDS: Yuba City Cogen-Walton Energy

 

22,865.28

(50,000.00)

(27,134.72)

9732181

R21-DIS: South Corner Dairy - Q1611-RD

 

3,303.83

(10,000.00)

(6,696.17)

9732182

WDT-SR: DG Cali Solar - Lodi Solar

 

1,002.49

(2,500.00)

(1,497.51)

9732260

WDT-ISP: LightsourceRe-Sawmill One Solar

 

4,284.92

(4,284.92)

-

9732262

WDT-ISP: ETCap-EastBayCommSolar1624-WD

 

7,951.22

(10,000.00)

(2,048.78)

9732263

R21-DIS:CupertinoElec-WonderfulOrch33018

 

4,639.53

(10,000.00)

(5,360.47)

9732264

WDT - C9P2 - FCDS - Paso Robles 1311-WD

 

11,302.71

(11,302.71)

-

9732301

MMA-Q632B-Summer Wheat Solar-ISO 60126C

 

3,804.54

(3,804.54)

-

9732302

R21-DIS: EnableEnergy-SpecialtyGran34412

 

1,802.98

(10,000.00)

(8,197.02)

9732303

WDT-FT: Zero Energy - Fallon Two Rock Rd

 

2,540.90

(1,000.00)

1,540.90

9732304

WDT-ISP: Ormat Nevada-Pease Reliability

 

964.51

(10,000.00)

(9,035.49)

9732305

WDT-FCDS: Ormat Nevada-Pease Reliability

 

5,607.16

(50,000.00)

(44,392.84)

9732320

WDT-SR:DGCal-MendocinoSolarHearstWillits

 

1,830.05

(1,830.05)

-

9732380

R21-DIS: EnableEnergy-SpecialtyGran34465

 

7,691.45

(10,000.00)

(2,308.55)

9732383

WDT-SR: PatmarLand-RuAnnDairyDig-1864-WD

 

3,062.83

(3,062.83)

-

9732388

WDT-SR: Silveira Ranch Solar A

 

2,173.80

(2,500.00)

(326.20)

9732389

WDT-SR: Silveira Ranch Solar B

 

42.36

(2,500.00)

(2,457.64)

9732390

WDT-SR: Silveira Ranch Solar C

 

42.36

(2,500.00)

(2,457.64)

9732391

WDT-SR: Silveira Ranch Solar D

 

42.36

(2,500.00)

(2,457.64)

9732400

WDT-SR: Apex Energy - Jade Solar 1865-WD

 

3,393.36

(2,500.00)

893.36

9732460

WDT-ISP: Solvida - PutahCreekSolarFarmN

 

 

(10,000.00)

(10,000.00)

9732461

WDT-FCDS: Solvida - PutahCreekSolarFarmN

 

1,466.11

 

1,466.11

9732462

WDT-FT: BeckwourthGrid-BeckwourthGrid 1

 

680.67

(1,000.00)

(319.33)

9732464

R21-DS: Daisy Renew - EarlJohn App 37593

 

10,460.15

(10,000.00)

460.15

9732467

R21-FS: West Biofuels-SunWest Bioenergy

 

3,995.73

(10,000.00)

(6,004.27)

9732480

WDT-SR: Forefront Power - Kern Sunset

 

2,181.32

(2,500.00)

(318.68)

9732482

WDT-FT: Kent Solar, LLC - KS Energy

 

659.11

(1,000.00)

(340.89)

9732483

WDT-SR: Forefront Power - Highway 43

 

435.15

(2,500.00)

(2,064.85)

9732484

R21-DS: CalCom Solar-Moonlight App 38001

 

4,448.45

(10,000.00)

(5,551.55)

9732486

R21-EIT: West Coast Waste-1827-RD Gen 1

 

8,755.92

(10,000.00)

(1,244.08)

9732487

R21-DS: Shasta College - Q#1753-RD

 

 

(10,000.00)

(10,000.00)

9732500

WDT-CS: Calpine - Cygnus Power Bank

 

2,228.95

(100,000.00)

(97,771.05)

9732501

WDT-FCDS: Calpine - Cygnus Power Bank

 

201.27

(50,000.00)

(49,798.73)

9732503

WDT-FT: CalCom Solar - Toyon

 

539.89

(1,000.00)

(460.11)

9732520

R21-DS: NextEra-BigDPacBuildSMF3-Q1791RD

 

1,544.82

(10,000.00)

(8,455.18)

9732523

WDT-SR: Forefront Power -Beard Q1888-WD

 

3,167.41

(2,500.00)

667.41

9732620

WDT-CS: ScoutClean-Gonzaga Ridge Wind 3

 

1,881.26

(1,881.26)

-

9732621

WDT-FCDS: ScoutClean-GonzagaRidgeWind3

 

40.07

(40.07)

-

9732622

WDT-EIT: FFPCACommSolar Rocha - 1783WD

 

5,687.45

(10,000.00)

(4,312.55)

9732660

R21-DS: Ecoplexus-CANatGuard-Q1786-RD

 

2,458.77

(10,000.00)

(7,541.23)

9732680

R21-DS: Cupertino E-Wonderful Orch 41293

 

5,812.68

(10,000.00)

(4,187.32)

9732720

R21-DS: SyntechBioenergy-RiverOakOrchard

 

8,786.28

(10,000.00)

(1,213.72)

9732721

R21-SR: Charlies Enterprises 1909-RD

 

 

(2,500.00)

(2,500.00)

9732780

MMA-Q954-Fifth Standard Solar-ISO 51419

 

315.71

(315.71)

-

9732781

Repower - Kelly Ridge Powerhouse - SFWPA

 

11,235.19

 

11,235.19

9732820

WDT-CS: Origis Operating-Vaquero Storage

 

2,304.43

(111,000.00)

(108,695.57)

9732821

WDT-FCDS: OrigisOperating-VaqueroStorage

 

80.15

(50,000.00)

(49,919.85)

9732840

WDT-SIS: Forefront Power - Kern Sunset

 

5,922.12

(10,000.00)

(4,077.88)

9732841

WDT-SIS: Forefront Power,LLC-Highway 43

 

3,324.35

(10,000.00)

(6,675.65)

9732842

R21-DS: COofCali DArrigo Bros 114202422

 

6,204.45

(10,000.00)

(3,795.55)

9732843

WDT-FT: SFPUC-Starr King PV Installation

 

1,399.71

(1,000.00)

399.71

9732844

R21-DS: BessieDig-HilltopHolsteins 38098

 

10,440.76

(10,000.00)

440.76

9732845

WDT-SR: Zero Energy Construct-Highway 43

 

164.29

(2,500.00)

(2,335.71)

9732846

WDT-CS: Calpine Corp-Panthera Power Bank

 

2,157.94

(79,000.00)

(76,842.06)

9732847

WDT-FCDS: CalpineCorp-PantheraPowerBank

 

40.07

(50,000.00)

(49,959.93)

9732848

WDT-CS: Capine Corp-Riverrun Power Bank

 

2,149.63

(99,000.00)

(96,850.37)

9732849

WDT-FCDS: CapineCorp-Riverrun Power Bank

 

40.07

(50,000.00)

(49,959.93)

9732880

R21-DS: ACElectric-RogerVGroningen 45330

 

4,316.39

(10,000.00)

(5,683.61)

9732881

MMA-Q946-Northern Orchard Solar-ISO51400

 

340.67

(340.67)

-

9732882

WDT-FT: Soltage-Bradley Gillett Solar 1

 

1,336.47

(1,000.00)

336.47

9732883

WDT-FT:Soltage-San Ardo Pine Vly Solar 1

 

681.80

(1,000.00)

(318.20)

9732900

WDT-SIS: RenewableProp-SilveiraRanchSolA

 

9,726.88

(10,000.00)

(273.12)

9732901

WDT-SIS: RenewableProp-SilveiraRanchSolB

 

5,924.65

(10,000.00)

(4,075.35)

9732902

WDT-SIS: RenewableProp-SilveiraRanchSolC

 

5,344.25

(10,000.00)

(4,655.75)

9732904

R21-DS: PhoenixEner-NapaRecBiomass2MW

 

4,057.37

(10,000.00)

(5,942.63)

9732905

R21-DS: AmericanCommod-AbelRoadBioenergy

 

8,270.62

(10,000.00)

(1,729.38)

9732906

MMA - Q1032 Tranquility 8 - ISO 51600

 

1,289.99

(1,289.99)

-

9732907

WDT-FT: Engie-Hayward EBCE Array

 

6,423.55

(1,000.00)

5,423.55

9732908

WDT-ISP:Berry Petroleum-Berry NMW Cogens

 

6,517.96

(60,000.00)

(53,482.04)

9732909

R21-DS: AmericanCommod-Willows Bioenergy

 

5,164.10

(10,000.00)

(4,835.90)

9732940

WDT-FAS: Bar20Dairy - Bar20Dairy1754-WD

 

 

(15,000.00)

(15,000.00)

9732941

MMA - Q1011 Colinas de Oro - ISO 51541

 

989.45

 

989.45

9732960

WDT-SR: PristineSunFund6-RGA2/SH1 Solar

 

1,585.32

(2,500.00)

(914.68)

9732961

R21-DS: Sunpower-TheGapInc-App46139NEMMT

4,781.63

(10,000.00)

(5,218.37)

9732962

R21-DS: City of Lincoln (Airport)

 

7,837.43

(10,000.00)

(2,162.57)

9733020

MMA - Q1129 Luna Valley - ISO 51746

 

648.01

(648.01)

-

9733060

WDT-EIT/SIS: ForefrontPower-Beard1888-WD

 

3,504.25

(10,000.00)

(6,495.75)

9733061

WDT-SR: Kent Solar, LLC - KS Energy

 

1,074.41

(2,500.00)

(1,425.59)

9733080

MMA1-Q1030 South Lake Solar-ISO 51604

 

767.96

(767.96)

-

9733081

WDT-SR: SoltageCaDevCo-SanArdoValleySol1

 

2,414.51

(2,500.00)

(85.49)

9733082

WDT-SR: Soltage,LLC-BradleyGillettSolar1

 

2,948.40

(2,500.00)

448.40

9733083

MMA1-NoQ Moss Landing Unit 6-ISO 51164

 

7,571.01

 

7,571.01

9733160

WDT-ISP: CalpineCorporation-CalSunSolar

 

3,936.36

(70,000.00)

(66,063.64)

9733161

WDT-ISP: REP Energy-V7 Solar Ranch

 

810.11

(810.11)

-

9733164

WDT-FT: GoldenStateRenew-GSRETurkIsland

 

1,614.22

(1,000.00)

614.22

9733165

WDT-FT: GoldenStateRenew - GSRE-OSP

 

452.64

(1,000.00)

(547.36)

9733166

R21-DS:ArcAlternativesElDoradoUHSD1782RD

 

180.63

(10,000.00)

(9,819.37)

9733167

MMA - Q1260 NoOrchard3Solar - ISO 51919

 

380.06

(380.06)

-

9733168

MMA - Q1259 NoOrchard2Solar - ISO 51918

 

702.27

(702.27)

-

9733169

WDT-FAS: GreenLightEnergy-Eagle 2 1620WD

 

246.90

(15,000.00)

(14,753.10)

9733180

MMA - QF FrickSummitRepower - ISO 51135

 

3,308.79

 

3,308.79

9733181

R21-DS: Google-MFABayviewFacSolar50088

 

1,236.29

(10,000.00)

(8,763.71)

9733182

WDT-FT: SoltageCA-AlamedaGrantLineSolar1

 

520.72

(520.72)

-

9733183

WDT-ISP: ZGlobal - Jade Solar_July 2018

 

12,927.54

(10,000.00)

2,927.54

9733200

R21-DS: PhoenixEnergy-NorthForkComPower

 

21,341.75

(10,000.00)

11,341.75

9733201

R21-DS: PhoenixEnergy-BlueMountainElectr

 

15,279.91

(10,000.00)

5,279.91

9733240

R21-DS: West Biofuels - Hat Creek Bioene

 

 

(10,000.00)

(10,000.00)

9733300

MMA-Q1120 Chestnut Westside-ISO 51818

 

243.72

(243.72)

-

9733301

MMA-Q1139 Westlands Solar Blue-ISO 51815

 

325.86

(325.86)

-

9733302

WDT-ISPReStudy: Strauss Wind Energy, LLC

 

7,903.67

(30,000.00)

(22,096.33)

9733303

EGI: Forbestown PH - SFWPA - Testing

 

342.45

 

342.45

9733304

WDT-SIS:Soltage,LLC-BradleyGillettSolar1

 

7,766.10

(10,000.00)

(2,233.90)

9733306

R21-DS-BASSLAKEJOINTELESchApp55332RESBCT

4,661.61

(10,000.00)

(5,338.39)

9733320

R21DIS:CityofMaderaRES-BCT (App 54517)

 

968.23

(10,000.00)

(9,031.77)

9733321

WDT-SIS:Soltage,SanArdoPineValleySolar1

 

5,536.12

(10,000.00)

(4,463.88)

9733322

Rule21:DS-MMRConsWAWONAFROZENFOODS-50318

360.26

(58,000.00)

(57,639.74)

9733323

WDT-FT-SolarElectricSolution-SEPVBarbar3

 

1,047.59

(1,000.00)

47.59

9733340

R21:DS-EL DORADO IRRIGATION DISTRICT

 

2,553.19

(10,000.00)

(7,446.81)

9733341

R21DIS:CA DEPT of CORRECTIONS(App55059)

 

514.77

(57,000.00)

(56,485.23)

9733360

MMA - Q1027 Blackbriar - ISO 51565 - COD

 

322.79

(322.79)

-

9733361

MMA - NoQ# - Patterson Pass - ISO 51137

 

1,701.30

(981.30)

720.00

9733380

WDT-FT-WildcatRenewableRPSantaCruzSolar1

 

2,376.99

(1,800.00)

576.99

9733381

WDT-FT-WildcatRenewableRPSantaCruzSolar2

 

2,448.89

(1,800.00)

648.89

9733382

Rule21:DS-JKB EnergySierraPacificAP55806

 

1,854.24

(59,000.00)

(57,145.76)

9733385

WDT-FT-ApexEnergySolutionsGasCoRdSolar1

 

345.48

(1,000.00)

(654.52)

9733427

MMA #5 - Q1036 Mustang 2 - ISO 51601

 

3,256.16

 

3,256.16

9733428

MMA-Q1116-Ultrapower Chinese-ISO 51707

 

1,241.16

(1,241.16)

-

9733440

WDT-SR-GoldenStateReneEng-GSRETurkIsland

 

 

(2,500.00)

(2,500.00)

9733480

Rule21:DS-DeltaDiabloCo-Digestion1968-RD

 

2,901.94

(10,000.00)

(7,098.06)

9733500

MMA-Q720&1002-LassenLodgeHydro-ISO 50773

730.85

(730.85)

-

9733540

WDT-FastTrack-Universal Solar-USPPGE9918

 

336.42

(1,000.00)

(663.58)

9733541

WDT-FastTrack-Universal Solar-USPPGE8918

 

336.42

(1,000.00)

(663.58)

9733542

WDT-FastTrack-Universal SolarUSPPGE-7918

 

199.30

(1,000.00)

(800.70)

9733543

WDT-FastTrack-Universal Solar-USPPGE6918

 

120.91

(1,000.00)

(879.09)

9733545

WDT-FastTrack-Universal Solar-USPPGE4918

 

120.91

(1,000.00)

(879.09)

9733546

WDT-FastTrack-Universal Solar-USPPGE3918

 

484.90

(1,000.00)

(515.10)

9733547

WDT-Fas Track-Universal Solar-USPPGE2918

 

199.30

(1,000.00)

(800.70)

9733548

WDT-Fast Track-UniversalSolar-USPPGE1918

 

738.22

(1,000.00)

(261.78)

9733549

WDT-FT-NatelEnergyc/oKinetMurphyHydro

 

683.50

(1,000.00)

(316.50)

9733550

WDT-FT-RENESOLAPOWERHOL-OspreySolar

 

1,281.94

(1,000.00)

281.94

9733552

WDT-PS-UticaWater&Power(UWPA)-AngelPower

3,360.47

(5,000.00)

(1,639.53)

9733553

WDT-FT-ReneSolaPowerHoldingsTaylorSolar

 

1,332.74

(1,000.00)

332.74

9733561

R21-Detailed Study-STAMOULES PRODUCE

 

2,397.22

(10,000.00)

(7,602.78)

9733562

Rule21DSBerryPetroleumCompy-BerryCogen18

 

538.41

 

538.41

9733581

WDT#SR-CITYOFHAYWARDHaywardEBCEArray

 

(2,500.00)

(2,500.00)

9733600

MMA-Q1278-Westwood Energy Ctr-ISO 52013

 

1,785.60

 

1,785.60

9733602

WDT:FT - Pine Flat Solar 1 - Apex Energy

 

525.33

(1,000.00)

(474.67)

9733603

WDT:FT - Merced 3 - Apex Energy

 

718.49

(1,000.00)

(281.51)

9733620

WDT-FastTrack-Calcom Solar-Sycamore-Napa

 

4,852.66

(1,000.00)

3,852.66

9733621

WDT-SIS- Kent Solar-LLC-KS Energy

 

606.93

 

606.93

9733640

WDT-SR-RenewableRPSantaCruzSolarQ2031WDT

1,852.11

(2,500.00)

(647.89)

9733641

WDT-SR-RenewableRPSantaCruzSolar1Q2030WD

1,852.11

(2,500.00)

(647.89)

9733642

R21#Detailed Study-Superior Packing Co.

 

694.40

(10,000.00)

(9,305.60)

9733643

R21:DS:NextEraEnerg114971313DGCAWestside

 

(58,000.00)

(58,000.00)

9733660

WDT-ISP/FCDS-DGCali-YubaCityEnergyStorag

 

323.95

(10,000.00)

(9,676.05)

9733681

WDT:FT - Corda I - Cratus Energy Mgmt

 

2,076.11

(1,000.00)

1,076.11

9733682

WDT:FT - Corda II - Cratus Energy Mgmt

 

2,076.11

(1,000.00)

1,076.11

9733700

MMA2 - Q1141 Alamo Springs - ISO 51745

 

530.79

 

530.79

9733701

MMA2 - Q1157 Alamo Springs 2 - ISO 51708

 

215.98

 

215.98

9733702

WDT:FT - Gonzales - FFP CA Com Solar

 

545.12

(1,000.00)

(454.88)

9733703

WDT:FT - Washoe Ave - FFP CA Com Solar

 

1,640.21

(1,000.00)

640.21

9733704

WDT:SR - Osprey Solar - Renesola Power

 

107.69

(2,500.00)

(2,392.31)

9733705

R21-DS: WonderfulPistachios&Almonds66478

 

 

(69,000.00)

(69,000.00)

9733720

R21-DS: Wonderful Pistachios & Almonds

 

 

(10,000.00)

(10,000.00)

9733761

MMA2 - Q1106 Fountain Wind - ISO 51770

 

803.51

 

803.51

9733762

WDT:ISP - Tranquility - FFP CA Com Solar

 

3,029.44

(10,000.00)

(6,970.56)

9733763

WDT:ISP - Munoz - FFP CA Com Solar

 

1,972.59

(10,000.00)

(8,027.41)

9733764

R21-DS: WonderfulPistachios&Almonds67792

 

1,215.61

(10,000.00)

(8,784.39)

9733765

WDT:SR - 2040-WD - Gas Co Road Solar 1

 

2,660.75

(2,500.00)

160.75

9733767

R21:DS - City of San Jose (App 68019)

 

 

(78,000.00)

(78,000.00)

9733780

WDT:ISP - Leo Solar - Apex Energy

 

212.76

(10,000.00)

(9,787.24)

9733840

R21:DS - RWA/UCM Cogen-Merced Co RWM

 

 

(10,000.00)

(10,000.00)

9733842

R21-DS: MacphersonOil-RoundMountainSolar

 

 

(10,000.00)

(10,000.00)

9733843

WDT-SR: SycamoreGroup-SycamoreNapa2066WD

 

(2,500.00)

(2,500.00)

9733862

WDT–FillInStudyReneSolaPowerTaylorSolar

 

71.77

(2,500.00)

(2,428.23)

9733881

MMA1 - Q1239 Medeiros Solar - ISO 40030

 

997.51

 

997.51

9733900

WDT-FT-ApexEnergySolutionsPineFlatSolar2

 

 

(1,000.00)

(1,000.00)

9733901

WDT-FT-ApexEnergSolutionGasCoRoadSolar2

 

 

(1,000.00)

(1,000.00)

9733920

WDT-SR-SolarElectricSolutionSEPVBarbara3

 

 

(2,500.00)

(2,500.00)

9733921

WDT–SR-Kinet Inc-Murphys Afterbay Hydro

 

1,102.67

(2,500.00)

(1,397.33)

9733922

Rule21:DS-GRANITEROCKCOMPANY(App69212)

 

(10,000.00)

(10,000.00)

9733923

WDT:SR-Manning Avenue-FFP CA Com Solar

 

794.60

(2,500.00)

(1,705.40)

9733924

Rule21-DS-ChicoElectricRoplastApp#4959

 

75.88

(10,000.00)

(9,924.12)

9733925

WDT-FT-Apex Energy Solutions-Lara Solar

 

642.84

(1,000.00)

(357.16)

9733926

WDT-FT-Apex Energy Solutions-Leo Solar2

 

251.25

(1,000.00)

(748.75)

9733929

WDT-FT-FFPCACommunitySolarBroadman2

 

 

(1,000.00)

(1,000.00)

9733930

WDT-SR-ApexEnergySolutionsPineFlatSolar1

 

830.47

(2,500.00)

(1,669.53)

9733931

Rule21DS-GOLDENSTATEFC-App71807

 

 

(10,000.00)

(10,000.00)

9733941

WDT-FT-ApexEnergySolutionsPineFlatSolar3

 

303.48

(1,000.00)

(696.52)

9734001

WDT:SR - 2083-WD-Corda 1 - Cratus Energy

 

 

(2,500.00)

(2,500.00)

9734002

WDT:SR - 2084-WD-Corda II-Cratus Energy

 

 

(2,500.00)

(2,500.00)

9734003

WDT-FT-ApexEnergySolutionsLLCLeoSolar3

 

 

(1,000.00)

(1,000.00)

9734045

WDT:FT - WHI Solano R&D - Wind Harvest

 

 

(1,000.00)

(1,000.00)

9734101

R21:DS - Fowler Packing Co - App 76191

 

 

(10,000.00)

(10,000.00)

9734102

R21:DS - Fowler Packing Co - App 76185

 

 

(10,000.00)

(10,000.00)

9734142

MMA1 - Q1010-Dyer - ISO 51539

 

152.83

 

152.83

9731721

R21-DIS-Syntech Bioenergy-Carriere Fam F

 

5,908.91

(10,000.00)

(4,091.09)

9732481

R21-DS: TONY MEIRINHO DAIRY AND SONS

 

3,623.13

 

3,623.13

9732760

R21-DS: Marysville Joint Unified School

 

1,924.68

(10,000.00)

(8,075.32)

9733120

R21-DS: County of Kern - Industrial

 

695.40

(10,000.00)

(9,304.60)

9733121

R21-DS: County of Kern - Mt. Vernon

 

869.41

(10,000.00)

(9,130.59)

9733560

Rule21:DSFresnoUnifiedSchoolSunnysideH.S

 

971.61

(10,000.00)

(9,028.39)

9733580

Rule21DS-Re-evaluation-SanJoaquinCounty

 

1,550.07

(10,000.00)

(8,449.93)

9726820

R21-Livermore Community Solar Frm-Det St

11,106.72

 

(11,106.72)

-

9729922

R21 Merced County RES-BCT Detailed Study

(7,575.61)

 

7,575.61

-

9731460

R21-DIS-Golden State FC-Golden State

 

8,899.68

(10,000.00)

(1,100.32)

9731625

R21-DIS-Crimson Resources-Crimson Resour

 

7,064.01

(10,000.00)

(2,935.99)

9732300

R21-EIT: SynTech-1627-RD Colusa Ind Park

 

7,862.46

(10,000.00)

(2,137.54)

9732850

R21-DS: ACElectric-SangerColdStor1844RD

 

2,583.93

(2,583.93)

-

 

Total Generation

(1,621,346.18)

1,120,039.17

(2,034,585.27)

(2,535,892.28)

 


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER REGULATORY ASSETS (Account 182.3)
  1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Assets being amortized, show period of amortization.
CREDITS
Line No.
DescriptionAndPurposeOfOtherRegulatoryAssets
Description and Purpose of Other Regulatory Assets
(a)
OtherRegulatoryAssets
Balance at Beginning of Current Quarter/Year
(b)
IncreaseDecreaseInOtherRegulatoryAssets
Debits
(c)
OtherRegulatoryAssetsWrittenOffAccountCharged
Written off During Quarter/Year Account Charged
(d)
OtherRegulatoryAssetsWrittenOffRecovered
Written off During the Period Amount
(e)
OtherRegulatoryAssets
Balance at end of Current Quarter/Year
(f)
1
AB802 Memo Account - Electric
325,759
593,605
919,364
2
(amortization: < 12 months)
3
AB802 Memo Account - Gas
266,531
485,676
752,207
4
(amortization: < 12 months)
5
Acc Amt - Plant RA Tax
161,887,481
3,520,572
165,408,053
6
(amortization: 11 years)
7
Accum Amort - URG Plant Reg Asset
3,520,575
3,520,575
8
(amortization: < 12 months)
9
Accum Amort - URG Plant Reg Asset Non Current
646,489,723
42,243,000
688,732,723
10
(amortization: 12 years)
11
AMCDOP- Cost Adjust Mechanism
49,846,489
54,347,071
66,232,297
37,961,263
12
(amortization: < 12 months)
13
Balancing Account - Utility Generation
13,857,924
2,346,308,203
2,253,502,275
78,948,004
14
(amortization: < 12 months)
15
BCA Charge Account
440,258
3,228,320
2,721,930
946,648
16
(amortization: <12 months)
17
Biomass Memo Account
357,908
51,287,488
22,554,764
29,090,632
18
(amortization: < 12 months)
19
Bioram Memo Account
5,775,726
16,787,864
13,111,548
9,452,042
20
(amortization: < 12 months)
21
CA Alternate Rates for Energy Program-Electric
23,438,916
516,932,147
497,729,243
42,641,820
22
(amortization: < 12 months)
23
CA Alternate Rates for Energy Program-Gas
21,906,240
124,145,197
126,548,962
24,310,005
24
(amortization: < 12 months)
25
CA Solar Initiative Thermal Program Memo Account
6,742,115
7,446,999
6,190,940
7,998,174
26
(amortization: < 12 months)
27
Catastrophic Event Memorandum Account
527,923,691
821,286,585
681,331,001
667,879,275
28
(amortization: <12 months)
29
CEE Incentive Electric Balancing Account
2,471,330
21,457
3,750,049
1,257,262
30
(amortization: < 12 months)
31
CEE Incentive Gas Balancing Account
212,379
550,223
146,331
616,271
32
(amortization: < 12 months)
33
Core Brokerage Fee
1,183,803
6,507,572
6,539,622
1,151,753
34
Amortization : < 12 MONTHS
35
Core Fixed Cost Gas Balancing Account
288,383,643
2,583,642,839
2,538,624,137
333,402,345
36
(amortization: < 12 months)
37
Core Pipeline Demand Charge Account
12,944,626
507,268,450
506,722,166
13,490,910
38
(amortization: < 12 months)
39
Critical Docs Program memo Acct NC
6,260,968
5,760,560
3,577,132
8,444,396
40
(amortization: > 12 months)
41
DCRBA - DCPP Employee Retention Program
66,678,204
33,891,874
32,786,330
42
(amortization : > 12 months)
43
Deferred Debit - Gas Reserves (Contra Balancing Ac
206,150,601
338,716,664
466,934,661
334,368,598
44
(amortization: < 12 months)
45
Demand Response Expenditures BA - DRAM
4,773,654
18,298,415
13,524,761
46
(amortization: > 12 months)
47
Demand Response Expenditures B/A (DREBA)
7,884,859
36,450,378
36,287,129
7,721,610
48
amortization: < 12 months
49
Department of Energy Litigation Balancing Account
15,017,083
15,230,427
29,270,198
29,056,854
50
(amortization: > 12 months)
51
Diablo Canyon Seismic Studies Balancing Acct
17,360,285
4,636,128
12,723,018
9,273,395
52
(amortization: < 12 months)
53
Diablo Canyon Retirement Bal Acct (DEPR) - NC
24,083,136
2,090,749
21,992,387
54
(amortization: > 12 months)
55
Distribution Revenue Adjustment Mechanism
71,915,222
4,908,351,283
4,676,758,177
159,677,884
56
(amortization: < 12 months)
57
Distributed Resources Plan Memorandum Acct
1,211,975
716,598
495,377
58
(amortization: > 12 months)
59
Electric Balancing Account Reserve Account
(a)
999,999,999
(f)
999,999,999
60
Electric Balancing Account Reserve Account
999,999,999
999,999,999
61
Electric Balancing Account Reserve Account
999,999,999
999,999,999
62
Electric Balancing Account Reserve Account
707,101,109
(e)
292,898,890
999,999,999
63
Electric Balancing Account Reserve Account
748,968,524
999,999,999
251,031,475
64
Electric Balancing Account Reserve Account
133,840,006
133,840,006
65
(amortization: < 12 months)
66
Electric Hazardous Substance Balancing Account
35,775,193
75,060,107
71,623,102
39,212,198
67
(amortization: < 12 months)
68
Electric Price Risk Management - Current
43,680,363
149,761,224
166,073,774
27,367,813
69
Electric Price Risk Management - NonCurrent
64,887,869
286,879,321
262,053,131
89,714,059
70
Electric Program Investment Charge
4,303,871
93,744,038
100,847,846
2,799,937
71
(amortization: < 12 months)
72
End-Use Customer Refund Adjustment
18,724,310
13,531,597
2,572,825
7,765,538
73
(amortization: < 12 months)
74
Energy Recovery Bonds Balancing Account
3,772,785
47,868,046
90,491,604
46,396,343
75
(amortization: < 12 months)
76
Energy Resource Recovery Account
70,591,762
3,731,544,376
3,855,245,475
53,109,337
77
(amortization: < 12 months)
78
Environmental Compliance
159,159,599
92,687,558
28,568,149
223,279,008
79
(amortization: 32 years)
80
Environmental Compliance Non-HSM
40,989,049
4,164,084
5,883,630
39,269,503
81
(amortization: 32 years)
82
Family Electric Rate Assistance Balancing Acct
6,396,125
5,340,841
6,396,125
5,340,841
83
(amortization: < 12 months)
84
FIN 47 - Regulatory Asset
17,558,036
3,921,979
2,325,533
19,154,482
85
Financing Costs - Current
1,507,230
126,659
1,380,571
86
(amortization: < 12 months)
87
Financing Costs Regulatory Asset
17,025,505
126,659
1,495,281
15,656,883
88
(amortization: 20 years)
89
Fire Hazard Prevention Memo Acct
1,078,845
384,213,494
76,516,282
308,776,057
90
(amortization: < 12 Months)
91
Gas Core Firm Storage Account
2,836,042
73,689,333
72,263,354
4,262,021
92
(amortization: < 12 months)
93
Gas Hazardous Substance Balancing Account
83,475,448
174,970,574
166,950,894
91,495,128
94
(amortization: < 12 months)
95
Gas Hazardous Substance Regulatory Asset
375,144,418
213,630,555
67,790,619
520,984,354
96
(amortization: 32 years)
97
Gas Non-Hazardous Substance Regulatory Asset
133,533,910
1,098,204
1,559,252
133,072,862
98
(amortization: 32 years)
99
Gas Pipeline Expense and Capital Balancing Account
3,436,048
404,792
3,538,382
302,458
100
(amortization: <12 months)
101
Gas Price Risk Management - Current
1,084,177
5,561,104
4,984,714
1,660,567
102
GPBA-Greenhouse Gas Compliance Subaccount
157,201,621
97,708,033
203,017,081
51,892,573
103
(amortization: < 12 months)
104
Gas Public Purpose Program Surcharge Memo Acct
45,383,994
262,600,117
263,513,722
44,470,389
105
(amortization: < 12 months)
106
Gas Transmission and Storage Memo Account (GTSMA)
180,904,540
120,214,886
188,206,878
112,912,548
107
(amortization: < 12 months)
108
Gas Transmission and Storage Revenue Sharing Mech.
18,143,605
409,981,159
435,704,157
7,579,393
109
(amortization: < 12 months)
110
GPBA - GHG Operational Cost Subaccount
27,406,445
20,648,625
42,120,504
5,934,566
111
(amortization: < 12 months)
112
Green Tariff Shared Renewables Bal Acct
106,047
10,165,144
5,772,392
4,498,799
113
(amortization: < 12 months)
114
Greem Tariff Shared Renewables Memo Acct
4,996,470
1,545,419
883,302
5,658,587
115
(amortization: < 12 months)
116
Greenhouse Gas Expense Memo Account - E
1,892,397
901,485
28,770
1,019,682
117
Greenhouse Gas Expense Memo Account - G
334,859
889,891
374,120
850,630
118
(amortization: < 12 months)
119
Hydro Licensing Balancing Account
20,372,843
1,304,870
28,015,544
47,083,517
120
Hydro Pipeline Testing Memo Acct
90,115,840
90,115,840
121
(amortization: > 12 months)
122
Integrated Distribution Energy Resources Account
71,232
151,908
223,140
123
(amortization: > 12 months)
124
Land Conserv. Plan Env. Remediation Memo Acct.
746,381
1,400,211
746,382
1,400,210
125
(amortization: < 12 months)
126
Line 407 Memo Acct NC
301,110
3,468,913
295,206
3,474,817
127
(amortization: > 12 months)
128
Major Emergency Balancing Account
288,710
103,517,472
125,770,895
21,964,713
129
(amortization: < 12 Months)
130
Miscellaneous Elec-Current-FERC Interest Bearing
57,292,448
1,291
57,291,157
131
(amortization: < 12 months)
132
Miscellaneous Electric Reg Asset - Current
481,041,835
171,448,117
623,567,816
28,922,136
133
(amortization: < 12 months)
134
Miscellaneous Electric Reg Asset - NonCurrent
9,638,677
413,600,941
259,694,970
163,544,648
135
(amortization: 25 years)
136
Miscellaneous Gas Reg Asset - Current
3,865,759
20,518,440
443,763
23,940,436
137
(amortization: < 12 months)
138
Mobile Home Park Balancing Account - Electric
7,093,489
37,835,958
26,368,081
18,561,366
139
(amortization: < 12 months)
140
Mobile Home Park Balancing Account - Gas
7,269,902
37,119,683
26,764,471
17,625,114
141
(amortization: < 12 months)
142
Modified transition cost balancing account
10,808,975
110,636,874
81,724,460
18,103,439
143
(amortization: < 12 months)
144
Negative Ongoing Competition Transition Chrg BA
3,089,668,292
109,931,615
179,905
3,199,420,002
145
(amortization: < 12 months)
146
New System Generation BA
46,650,016
321,811,469
156,216,930
118,944,523
147
(amortization: < 12 months)
148
New Environmental Regulations Balancing Acct
34,249,572
23,699,624
10,549,948
149
(amortization: < 12 months)
150
Non Current HSM BA Elec
38,439,275
57,450,004
67,007,423
28,881,856
151
(amortization: > 12 months)
152
Non Current HSM BA Gas
89,691,641
134,050,008
156,350,654
67,390,995
153
(amortization: > 12 months)
154
Noncurr Wildfire Exp Memo Acct - Elec
213,354,963
213,354,963
155
(amortization: > 12 months)
156
Noncurr Wildfire Exp Memo Acct - Gas
103,948,670
103,948,670
157
(amortization: > 12 months)
158
Nuclear Decommissioning Adjustment Mechanism
45,752,788
69,235,497
40,935,684
17,452,975
159
(amortization: 2 years)
160
Nuclear Regulatory Commission Rulemaking Costs BA
8,001,467
42,424,044
36,255,129
14,170,382
161
(amortization: > 12 Months)
162
Pension Regulatory Asset
1,953,963,992
151,311,609
158,171,730
1,947,103,871
163
(amortization: indefinite)
164
Procurement Energy Efficiency Rev. Adj. Mechanism
11,603,488
334,265,163
337,429,250
8,439,401
165
(amortization: < 12 months)
166
Public Purpose Programs Revenue Adjustment Mech.
26,720,208
203,534,997
205,662,867
28,848,078
167
(amortization: < 12 months)
168
Purchased Gas Balancing Account
2,119,259
1,629,992,206
1,621,443,629
10,667,836
169
(amortization: < 12 months)
170
Reg Asset - Abandoned Capital Projects
18,324,235
20,622,784
13,928,167
25,018,852
171
(amortization: < 12 months)
172
Reg Asset - Mobilehome park BA - E Noncurrent
15,117,286
18,860,040
9,244,074
24,733,252
173
(amortization: < 12 months)
174
Reg Asset - Mobilehome park BA - G Noncurrent
17,475,604
16,982,398
6,741,494
27,716,508
175
(amortization: < 12 months)
176
Reg Asset - Mobilehome park BA - E Current
1,622,479
3,546,678
2,737,651
2,431,506
177
(amortization: < 12 months)
178
Reg Asset - Mobilehome park BA - G Current
1,806,908
3,990,547
3,066,169
2,731,286
179
(amortization: < 12 months)
180
Reg Asset - Hydro Non Current
10,758,023
107,529
9,107
10,856,445
181
(amortization: > 12 months)
182
Reg Asset - Cema Elec Non Current
322,049,440
910,598,355
239,781,569
992,866,226
183
(amortization: > 12 months)
184
Reg Asset - Cema Gas Non Current
26,429,472
24,417,732
2,128,697
48,718,507
185
(amortization: > 12 months)
186
Reg Asset - Miscellaneous Gas - Non-Current
101,035,834
70,274,180
30,761,654
187
(amortization: > 12 months)
188
Reliability Services Balancing Account
410,816
69,850,963
125,330,531
55,890,384
189
(amortization: < 12 months)
190
Residential Rate Reform Memorandum Account (RRRMA)
19,253,940
18,292,957
20,910,559
16,636,338
191
(amortization: < 12 months)
192
Tax Normalization Memo Account (TNMA)
9,965,012
9,464,934
4,165,656
15,264,290
193
(amortization: > 12 months)
194
Transition Cost - Noncore Balancing Account
2,314,575
180,038,106
211,168,204
33,444,673
195
(amortization: < 12 months)
196
Transmission Access Charge Balancing Account
139,010,141
455,486,736
466,887,276
127,609,601
197
(amortization: < 12 months)
198
Transmission Revenue Balancing Account
101,030,150
269,566,411
239,282,193
70,745,932
199
(amortization: < 12 months)
200
Unamortized Financial Hedging Cost
12,779,845
836,195
11,943,650
201
(amortization: 20 years)
202
Unamortized Financial Hedging Cost Current
836,195
836,195
203
(amortization: < 12 months)
204
URG Plant Regulatory Asset - current
42,239,000
42,239,000
205
(amortization: < 12 months)
206
URG Plant Regulatory Asset - noncurrent
944,805,000
944,805,000
207
(amortization: 22 years)
208
URG Plant Regulatory Asset - Tax
183,010,953
183,010,953
209
(amortization: 11 years)
210
Vegetation Management Reg. Asset - Current
15,848,080
163,110,849
156,874,793
22,084,136
211
(amortization: < 12 months)
212
Wildfires Customer Protections Memo Acct - E
2,209,780
2,209,780
213
(amortization: > 12 months)
214
Wildfires Customer Protections Memo Acct - G
1,579,497
1,579,497
215
(amortization: > 12 months)
216
Miscellaneous minor items
219,928,700
359,284,630
579,094,281
119,049
44
TOTAL
5,018,800,793
26,561,571,526
25,734,889,740
5,845,482,579


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OtherRegulatoryAssets

The FERC software will not allow the entire beginning balance of Electric Balancing Account Reserve Account of ($3,707,101,106) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 16: ($999,999,999)

Line 17: ($999,999,999)

Line 18: ($999,999,999)

Line 19: ($707,101,109)

Total ($3,707,101,106)

(b) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Primarily internal labor expenses. Offset to 182.3 - Other Regulatory Assets.

(c) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Primarily internal labor expenses. Offset to 182.3 - Other Regulatory Assets, 549 - Misc. Other Power Generation Expenses and 253 - Other Deferred Credits.

(d) Concept: OtherRegulatoryAssetsWrittenOffAccountCharged

Primarily Wildfire Expense Memo Account-Electric, Wildfire Expense Memo Account-Gas and Transmission Integrity Management Balancing Account with offsets to 400.

(e) Concept: OtherRegulatoryAssetsWrittenOffRecovered

The FERC software will not allow the entire credit balance of Electric Balancing Account Reserve Account of ($1,426,738,895) to be shown, as it is too large. As such, the balance has been broken into the following:

 

 

Line 19: $292,898,890

Line 20: $999,999,999

Line 21: $133,840,006

Total $1,426,738,895

(f) Concept: OtherRegulatoryAssets

The FERC software will not allow the entire ending balance of Electric Balancing Account Reserve Account of ($4,384,871,477) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 16: ($999,999,999)

Line 17: ($999,999,999)

Line 18: ($999,999,999)

Line 19: ($999,999,999)

Line 20: ($251,031,475)

Line 21: ($133,840,006)

Total ($4,384,871,477)


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
  1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
  2. For any deferred debit being amortized, show period of amortization in column (a)
  3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by classes.
CREDITS
Line No.
Description of Miscellaneous Deferred Debits
(a)
Balance at Beginning of Year
(b)
Debits
(c)
Credits Account Charged
(d)
Credits Amount
(e)
Balance at End of Year
(f)
1
Undistributed Charges
10,756,425
1,138,612,174
1,147,137,951
19,282,202
2
Customer Adv for Construction
7,277,615
1,154,553
776,326
7,655,842
3
Development Costs
62,235,288
2,661,177
19,283,495
45,612,970
4
Payments for MLX and
5
Non-Energy Invoices
1,370,556
724,044,888
724,006,244
1,409,200
6
Payments for Main Line
7
Extension
6,311,326
197,112,042
202,297,724
11,497,008
8
Clearing Account for
9
JP Morgan Chase
1,271,127
23,841,842
24,006,900
1,106,069
10
Payroll Clearing Account
201,506
12,670,981,026
12,670,843,910
338,622
11
Land Surplus
480,219
559,044
1,039,263
12
Credit Card Clearing Account
275,299
8,520,349
7,963,968
281,082
13
Miscellaneous minor items
58,403
(a)
131,790,040
132,439,144
590,701
47
Miscellaneous Work in Progress
48
Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49
TOTAL
55,551,664
26,073,137


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: IncreaseInMiscellaneousDeferredExpense

Activity primarily reflects undistributed cash receipts.

(b) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131, 142

(c) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 456, 495

(d) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131, 143

(e) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131, 252

(f) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131, 143, 559

 

(g) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131

(h) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged: 131

(i) Concept: DecreaseInMiscellaneousDeferredExpenseAccountCharged

Typical Accounts charged 182.3 and 236


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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.
Line No.
DescriptionOfAccumulatedDeferredIncomeTax
Description and Location
(a)
AccumulatedDeferredIncomeTaxes
Balance at Beginning of Year
(b)
AccumulatedDeferredIncomeTaxes
Balance at End of Year
(c)
1
Electric
2
Environmental
93,803,083
42,478,580
3
Compensation
94,297,980
50,033,114
4
CIAC
146,286,875
121,829,617
5
Injuries and Damages
102,846,333
3,478,176,873
6
California Corporation Franchise Tax
161,001,489
145,217,541
7
Other
170,762,620
437,277,748
8 TOTAL Electric (Enter Total of lines 2 thru 7)
52,706,776
3,071,841,583
9
Other (Specify)
10
Environmental
57,056,261
77,136,703
11
Compensation
45,329,183
36,918,182
12
CIAC
204,929,511
168,443,372
13
Injuries and Damages
54,950,921
39,315,702
14
California Corporation Franchise Tax
26,584,707
45,289,022
15
Other
1,223,174,711
1,372,702,830
16 TOTAL Gas (Enter Total of lines 10 thru 15)
1,334,841,516
1,416,322,957
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)
1,728,161,422
(a)
5,025,590,626
Notes
Line 15 - Other Amount primarily relates to net operating loss carryforwards. Line 17 - Other Balance at Balance beginning of at end of the year the year California Corporation Franchise Tax (42,937,411) (24,571,408) Compensation 3,352,706 2,353,117 Other 485,611,387 559,644,377 Total 446,026,682 537,426,086


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxes

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
CAPITAL STOCKS (Account 201 and 204)
  1. Report below the particulars (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. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
  2. Entries in column (b) 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 Series
(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 amount outstanding without reduction for amounts held by respondent) Shares
(e)
Outstanding per Bal. Sheet (Total amount outstanding without reduction for amounts held by respondent) 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
1,321,874,045
6
Preferred Stock (Account 204)
7
8
9
10
Total
257,994,575
1
Capital Stock (Accounts 201 and 204) - Data Conversion
2
Pacific Gas and Electri Company's stock
3
is wholly owned by PG&E Corporation
4
Common
800,000,000
5
264,374,809
1,321,874,045
5
TOTAL COMMON
800,000,000
5
264,374,809
1,321,874,045
6
Registered with the American Stock Exchange
7
Preferred, Cumulative:
8
Redeemable: WIthout Mandatory Redemption
9
4.36%
418,291
25
25.75
418,291
10,457,275
10
4.50%
611,142
25
26
611,142
15,278,550
11
4.80%
793,031
25
27.25
793,031
19,825,775
12
5.00%
1,778,172
25
26.75
1,778,172
44,454,300
13
5.00% - Series A
934,322
25
26.75
934,322
23,358,050
14
(a)
7.04%
3,000,000
25
15
Undesignated in Class
56,180,217
25
16
SubTotal Redeemable Without
63,715,175
4,534,958
113,373,950
17
Mandatory Redemption
18
Registered with the American Stock Exchange
19
Non-Redeemable
20
5.00%
400,000
25
400,000
10,000,000
21
5.50%
1,173,163
25
1,173,163
29,329,075
22
6.00%
4,211,662
25
4,211,662
105,291,550
23
SubTotal Non-Redeemable
5,784,825
5,784,825
144,620,625
24
Redeemable: With Mandatory Redemption
25
(b)
6.30%
2,500,000
25
26
(c)
6.57%
3,000,000
25
27
Undesignated in Class
10,000,000
100
28
SubTotal Redeemable With
15,500,000
29
Mandatory Redemption
30
TOTAL PREFERRED
85,000,000
10,319,783
257,994,575
31
Total


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: CapitalStockDescription

Redeemed on August 31, 2005.

(b) Concept: CapitalStockDescription

This was reclassifed to Other Long-Term Debt in accordance with ASC 480 in September 2003.

It was shown here since it is still part of the total number of preferred shares

authorized. They were fully redeemed on May 31, 2005.

(c) Concept: CapitalStockDescription

This was reclassifed to Other Long-Term Debt in accordance with ASC 480 in September 2003.

It was shown here since it is still part of the total number of preferred shares

authorized. They were fully redeemed on May 31, 2005.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-16
Year/Period of Report

End of:
2018
/
Q4
Other Paid-in Capital
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
Histrocal Data - Other Paid in Capital
18
OtherPaidInCapitalDetail
Beginning Balance Amount
19.1
IncreasesDecreasesInOtherPaidInCapital
Account 211 - Miscellaneous Paid in Capital
19.2
IncreasesDecreasesInOtherPaidInCapital
Equity Infusions from Parent Company
6,729,587,624
19.3
IncreasesDecreasesInOtherPaidInCapital
Excess Tax Benefit on Stock Based Compensation
50,960,304
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
6,780,547,928


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
CAPITAL STOCK EXPENSE (Account 214)
  1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
  2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (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)
1
COMMON
25,143,083
2
PREFERRED, CUMULATIVE:
3
Redeemable - $25 par value per share:
4
4.36%
29,509
5
4.50%
387,663
6
4.80%
777,999
7
5.00%
1,758,375
8
5.00% - Series A
158,204
9
Non-Redeemable - $25 par value per share:
10
5.00%
73,717
11
5.50%
173,730
12
6.00%
449,606
22
TOTAL
28,951,886


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
LONG-TERM DEBT (Account 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 (f). Explain in a footnote any difference between the total of column (f) 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.
ClassAndSeriesOfObligationCouponRateDescription
Class and Series of Obligation, Coupon Rate (For new issue, give commission Authorization numbers and dates)
(a)
RelatedAccountNumber
Related Account Number
(b)
Principal Amount of Debt Issued
(c)
LongTermDebtIssuanceExpensePremiumOrDiscount
Total Expense, Premium or Discount
(d)
LongTermDebtIssuanceExpenses
Total Expense
(e)
LongTermDebtPremium
Total Premium
(f)
LongTermDebtDiscount
Total Discount
(g)
NominalDateOfIssue
Nominal Date of Issue
(h)
DateOfMaturity
Date of Maturity
(i)
AmortizationPeriodStartDate
AMORTIZATION PERIOD Date From
(j)
AmortizationPeriodEndDate
AMORTIZATION PERIOD Date To
(k)
Outstanding (Total amount outstanding without reduction for amounts held by respondent)
(l)
Interest for Year Amount
(m)
1
Bonds (Account 221)
2
3
4
5
Subtotal
18,387,100,000
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
Long Term Debt (Historical Data)
1
ACCOUNT 221:
2
SENIOR NOTES & POLLUTION CONTROL BONDS:
3
Series Rate
4
Series 6.05% Senior Notes due 2034 6.050%
3,000,000,000
30,717,515
(e)
03/23/2004
(av)
03/01/2034
(cm)
03/23/2004
(ed)
03/01/2034
3,000,000,000
181,500,000
5
14,640,000
6
Series 5.80% Senior Notes due 2037 5.800%
700,000,000
6,807,234
(f)
03/13/2007
(aw)
03/01/2037
(cn)
03/13/2007
(ee)
03/01/2037
700,000,000
40,600,000
7
3,822,000
8
Series 6.35% Senior Notes due 2038 6.350%
400,000,000
3,943,976
(g)
03/03/2008
(ax)
02/15/2038
(co)
03/03/2008
(ef)
02/15/2038
400,000,000
25,400,000
9
568,000
10
Series 8.25% Senior Notes due 2018 8.250%
600,000,000
4,572,075
(h)
10/21/2008
(ay)
10/15/2018
(cp)
10/21/2008
(eg)
10/15/2018
(fu)
2,154,167
11
9,942,000
12
Series 8.25% Senior Notes due 2018 8.250%
200,000,000
1,511,598
(i)
11/18/2008
(az)
10/15/2018
(cq)
11/18/2008
(eh)
10/15/2018
(fv)
2,154,167
13
8,950,000
14
Series 6.25% Senior Notes due 2039 6.250%
550,000,000
5,145,853
(j)
03/06/2009
(ba)
03/01/2039
(cr)
03/06/2009
(ei)
03/01/2039
550,000,000
34,375,000
15
6,814,500
16
Series 5.4% Senior Notes due 2040 5.400%
550,000,000
5,435,842
(k)
11/18/2009
(bb)
01/15/2040
(cs)
11/18/2009
(ej)
01/15/2040
550,000,000
29,700,000
17
7,815,500
18
Series 5.8% Senior Notes due 2037 5.800%
250,000,000
2,562,097
(l)
04/01/2010
(bc)
03/01/2037
(ct)
04/01/2010
(ek)
03/01/2037
250,000,000
14,500,000
19
3,862,500
20
Series 3.5% Senior Notes due 2020 3.500%
550,000,000
4,205,770
(m)
09/15/2010
(bd)
10/01/2020
(cu)
09/15/2010
(el)
10/01/2020
550,000,000
19,250,000
21
2,728,000
22
Series 3.5% Senior Notes due 2020 3.500%
250,000,000
1,897,267
(n)
11/18/2010
(be)
10/01/2020
(cv)
11/18/2010
(em)
10/01/2020
250,000,000
8,750,000
23
6,840,000
24
Series 5.4% Senior Notes due 2040 5.400%
250,000,000
2,459,767
(o)
11/18/2010
(bf)
01/15/2040
(cw)
11/18/2010
(en)
01/15/2040
250,000,000
13,500,000
25
6,252,500
26
Series 4.25% Senior Notes due 2021 4.250%
300,000,000
2,270,404
(p)
05/13/2011
(bg)
05/15/2021
(cx)
05/13/2011
(eo)
05/15/2021
300,000,000
12,750,000
27
243,000
28
Series 3.25% Senior Notes due 2021 3.250%
250,000,000
1,981,515
(q)
09/12/2011
(bh)
09/15/2021
(cy)
09/12/2011
(ep)
09/15/2021
250,000,000
8,125,000
29
1,312,500
30
Series 4.5% Senior Notes due 2041 4.50%
250,000,000
2,576,302
(r)
12/01/2011
(bi)
12/15/2041
(cz)
12/01/2011
(eq)
12/15/2041
250,000,000
11,250,000
31
862,500
32
Series 4.45% Senior Notes due 2042 4.45%
400,000,000
4,062,665
(s)
04/16/2012
(bj)
04/15/2042
(da)
04/16/2012
(er)
04/15/2042
400,000,000
17,800,000
33
2,036,000
34
Series 2.45% Senior Notes due 2022 2.45%
400,000,000
3,251,743
(t)
08/16/2012
(bk)
08/16/2022
(db)
08/16/2012
(es)
08/16/2022
400,000,000
9,800,000
35
1,164,000
36
Series 3.75% Senior Notes due 2042 3.75%
350,000,000
3,632,775
(u)
08/16/2012
(bl)
08/16/2042
(dc)
08/16/2012
(et)
08/16/2042
350,000,000
13,125,000
37
311,500
38
Series 3.25% Senior Notes due 2023 3.25%
375,000,000
2,924,964
(v)
06/14/2013
(bm)
06/15/2023
(dd)
06/14/2013
(eu)
06/15/2023
375,000,000
12,187,500
39
1,901,250
40
Series 4.6% Senior Notes due 2043 4.60%
375,000,000
3,768,714
(w)
06/14/2013
(bn)
06/15/2043
(de)
06/14/2013
(ev)
06/15/2043
375,000,000
17,250,000
41
303,750
42
Series 3.85% Senior Notes due 2023 3.85%
300,000,000
2,505,170
(x)
11/12/2013
(bo)
11/15/2023
(df)
11/12/2013
(ew)
11/15/2023
300,000,000
11,550,000
43
543,000
44
Series 5.125% Senior Notes due 2043 5.125%
500,000,000
5,099,524
(y)
11/12/2013
(bp)
11/15/2043
(dg)
11/12/2013
(ex)
11/15/2043
500,000,000
25,625,000
45
765,000
46
Series 3.75% Senior Notes due 2024 3.75%
450,000,000
3,672,801
(z)
02/21/2014
(bq)
02/15/2024
(dh)
02/21/2014
(ey)
02/15/2024
450,000,000
16,875,000
47
445,500
48
Series 4.75% Senior Notes due 2044 4.75%
450,000,000
4,685,300
(aa)
02/21/2014
(br)
02/15/2044
(di)
02/21/2014
(ez)
02/15/2044
450,000,000
21,375,000
49
1,921,500
50
Series 3.4% Senior Notes due 2024 3.40%
350,000,000
2,788,492
(ab)
08/18/2014
(bs)
08/15/2024
(dj)
08/18/2014
(fa)
08/15/2024
350,000,000
11,900,000
51
262,500
52
Series 4.75% Senior Notes due 2044 4.75%
225,000,000
2,298,853
(ac)
08/18/2014
(bt)
02/15/2044
(dk)
08/18/2014
(fb)
02/15/2044
225,000,000
10,687,500
53
13,594,500
54
Series 4.3% Senior Notes due 2045 4.30%
500,000,000
5,051,799
(ad)
11/06/2014
(bu)
03/15/2045
(dl)
11/06/2014
(fc)
03/15/2045
500,000,000
21,500,000
55
5,745,000
56
Series 3.50% Senior Notes due 2025 3.50%
400,000,000
3,471,059
(ae)
06/12/2015
(bv)
06/15/2025
(dm)
06/12/2015
(fd)
06/15/2025
400,000,000
14,000,000
57
2,540,000
58
Series 4.30% Senior Notes due 2045 4.30%
100,000,000
1,092,707
(af)
06/12/2015
(bw)
03/15/2045
(dn)
06/12/2015
(fe)
03/15/2045
100,000,000
4,300,000
59
5,231,000
60
Series 3.50% Senior Notes due 2025 3.50%
200,000,000
1,709,814
(ag)
11/05/2015
(bx)
06/15/2025
(do)
11/05/2015
(ff)
06/15/2025
200,000,000
7,000,000
61
2,716,000
62
Series 4.25% Senior Notes due 2046 4.25%
450,000,000
4,859,582
(ah)
11/05/2015
(by)
03/15/2046
(dp)
11/05/2015
(fg)
03/15/2046
450,000,000
19,125,000
63
8,415,000
64
Series 2.95% Senior Notes due 2026 2.95%
600,000,000
5,241,785
(ai)
03/01/2016
(bz)
03/01/2026
(dq)
03/01/2016
(fh)
03/01/2026
600,000,000
17,700,000
65
1,596,000
66
Series 4.00% Senior Notes due 2046 4.00%
400,000,000
4,345,973
(aj)
12/01/2016
(ca)
12/01/2046
(dr)
12/01/2016
(fi)
12/01/2046
400,000,000
16,000,000
67
7,344,000
68
Series 4.00% Senior Notes due 2046 4.00%
200,000,000
2,102,746
(ak)
03/10/2017
(cb)
12/01/2046
(ds)
03/10/2017
(fj)
12/01/2046
200,000,000
(fw)
8,000,000
69
4,136,000
70
Series 3.30% Senior Notes due 2027 3.30%
400,000,000
3,306,994
(al)
03/10/2017
(cc)
03/15/2027
(dt)
03/10/2017
(fk)
03/15/2027
400,000,000
(fx)
13,200,000
71
1,420,000
72
Series 3.30% Senior Notes due 2027 3.30%
1,150,000,000
9,322,742
(am)
11/29/2017
(cd)
12/01/2027
(du)
11/29/2017
(fl)
12/01/2027
1,150,000,000
(fy)
37,950,000
73
3,404,000
74
Series 3.95% Senior Notes due 2047 3.95%
850,000,000
8,803,613
(an)
11/29/2017
(ce)
12/01/2047
(dv)
11/29/2017
(fm)
12/01/2047
850,000,000
(fz)
33,575,000
75
3,706,000
76
(a)
Series 4.25% Senior Notes due 2023 4.25%
500,000,000
4,061,237
(ao)
08/06/2018
(cf)
08/01/2023
(dw)
08/06/2018
(fn)
08/01/2023
500,000,000
8,559,028
77
1,175,000
78
(b)
Series 4.65% Senior Notes due 2028 4.65%
300,000,000
2,587,341
(ap)
08/06/2018
(cg)
08/01/2028
(dx)
08/06/2018
(fo)
08/01/2028
300,000,000
5,618,750
79
852,000
80
Pollution Control Bonds
81
1996 Series C/E/F Various
465,000,000
2,485,410
(aq)
05/23/1996
(ch)
11/01/2026
(dy)
05/23/1996
(fp)
11/01/2026
465,000,000
6,176,618
82
1997 Series B Various
148,550,000
886,179
(ar)
09/16/1997
(ci)
11/01/2026
(dz)
09/16/1997
(fq)
11/01/2026
148,550,000
2,047,926
83
(c)
2008 Series F-G Various
95,000,000
312,026
(as)
06/15/2017
(ea)
06/15/2017
50,000,000
1,308,124
84
2009 Series A-B Various
148,550,000
806,484
(at)
09/01/2009
(ck)
11/01/2026
(eb)
09/01/2009
(fs)
11/01/2026
148,550,000
1,965,341
85
2010 Series E 1.75%
50,000,000
328,903
(au)
06/15/2017
(cl)
11/01/2026
(ec)
06/15/2017
(ft)
11/01/2026
50,000,000
875,000
86
SUBTOTAL ACCOUNT 221
19,232,100,000
271,215,110
18,387,100,000
791,084,121
33 TOTAL
19,232,100,000
271,215,110
18,387,100,000
791,084,121


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

Refer to Note 6 on page 109, for CPUC authorization number and date.

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

Refer to Note 6 on page 109, for CPUC authorization number and date.

(c) Concept: ClassAndSeriesOfObligationCouponRateDescription

In December 2018, the Utility's $45 million principal amount of 1.05% Series 2008 G Pollution Control Bonds matured and were repaid.

(d) Concept: LongTermDebtIssuanceExpensePremiumOrDiscount

Items included under column (c) represent original issuance expense, premium or discount on issuance related to outstanding debt which are recoverable through the cost of capital mechanism. Other financing related costs which are also recoverable are reflected on page 232, Other Regulatory Assets (Account 182.3).

(e) Concept: NominalDateOfIssue
Original value: 3/23/04
(f) Concept: NominalDateOfIssue
Original value: 3/13/07
(g) Concept: NominalDateOfIssue
Original value: 3/3/08
(h) Concept: NominalDateOfIssue
Original value: 10/21/08
(i) Concept: NominalDateOfIssue
Original value: 11/18/08
(j) Concept: NominalDateOfIssue
Original value: 3/6/09
(k) Concept: NominalDateOfIssue
Original value: 11/18/09
(l) Concept: NominalDateOfIssue
Original value: 4/1/10
(m) Concept: NominalDateOfIssue
Original value: 9/15/10
(n) Concept: NominalDateOfIssue
Original value: 11/18/10
(o) Concept: NominalDateOfIssue
Original value: 11/18/10
(p) Concept: NominalDateOfIssue
Original value: 5/13/11
(q) Concept: NominalDateOfIssue
Original value: 9/12/11
(r) Concept: NominalDateOfIssue
Original value: 12/1/11
(s) Concept: NominalDateOfIssue
Original value: 4/16/2012
(t) Concept: NominalDateOfIssue
Original value: 8/16/12
(u) Concept: NominalDateOfIssue
Original value: 8/16/12
(v) Concept: NominalDateOfIssue
Original value: 6/14/13
(w) Concept: NominalDateOfIssue
Original value: 6/14/13
(x) Concept: NominalDateOfIssue
Original value: 11/12/13
(y) Concept: NominalDateOfIssue
Original value: 11/12/13
(z) Concept: NominalDateOfIssue
Original value: 2/21/14
(aa) Concept: NominalDateOfIssue
Original value: 2/21/14
(ab) Concept: NominalDateOfIssue
Original value: 8/18/14
(ac) Concept: NominalDateOfIssue
Original value: 8/18/14
(ad) Concept: NominalDateOfIssue
Original value: 11/6/14
(ae) Concept: NominalDateOfIssue
Original value: 6/12/15
(af) Concept: NominalDateOfIssue
Original value: 6/12/15
(ag) Concept: NominalDateOfIssue
Original value: 11/5/15
(ah) Concept: NominalDateOfIssue
Original value: 11/5/15
(ai) Concept: NominalDateOfIssue
Original value: 3/1/16
(aj) Concept: NominalDateOfIssue
Original value: 12/1/16
(ak) Concept: NominalDateOfIssue
Original value: 3/10/2017
(al) Concept: NominalDateOfIssue
Original value: 3/10/17
(am) Concept: NominalDateOfIssue
Original value: 11/29/17
(an) Concept: NominalDateOfIssue
Original value: 11/29/17
(ao) Concept: NominalDateOfIssue
Original value: 8/6/2018
(ap) Concept: NominalDateOfIssue
Original value: 8/6/2018
(aq) Concept: NominalDateOfIssue
Original value: 5/23/96
(ar) Concept: NominalDateOfIssue
Original value: 9/16/97
(as) Concept: NominalDateOfIssue
Original value: 6/15/17
(at) Concept: NominalDateOfIssue
Original value: 9/1/09
(au) Concept: NominalDateOfIssue
Original value: 6/15/17
(av) Concept: DateOfMaturity
Original value: 3/1/34
(aw) Concept: DateOfMaturity
Original value: 3/1/37
(ax) Concept: DateOfMaturity
Original value: 2/15/38
(ay) Concept: DateOfMaturity
Original value: 10/15/18
(az) Concept: DateOfMaturity
Original value: 10/15/18
(ba) Concept: DateOfMaturity
Original value: 3/1/39
(bb) Concept: DateOfMaturity
Original value: 1/15/40
(bc) Concept: DateOfMaturity
Original value: 3/1/37
(bd) Concept: DateOfMaturity
Original value: 10/1/20
(be) Concept: DateOfMaturity
Original value: 10/1/20
(bf) Concept: DateOfMaturity
Original value: 1/15/40
(bg) Concept: DateOfMaturity
Original value: 5/15/21
(bh) Concept: DateOfMaturity
Original value: 9/15/21
(bi) Concept: DateOfMaturity
Original value: 12/15/41
(bj) Concept: DateOfMaturity
Original value: 4/15/42
(bk) Concept: DateOfMaturity
Original value: 8/16/22
(bl) Concept: DateOfMaturity
Original value: 8/16/42
(bm) Concept: DateOfMaturity
Original value: 6/15/23
(bn) Concept: DateOfMaturity
Original value: 6/15/43
(bo) Concept: DateOfMaturity
Original value: 11/15/23
(bp) Concept: DateOfMaturity
Original value: 11/15/43
(bq) Concept: DateOfMaturity
Original value: 2/15/24
(br) Concept: DateOfMaturity
Original value: 2/15/44
(bs) Concept: DateOfMaturity
Original value: 8/15/24
(bt) Concept: DateOfMaturity
Original value: 2/15/44
(bu) Concept: DateOfMaturity
Original value: 3/15/45
(bv) Concept: DateOfMaturity
Original value: 6/15/25
(bw) Concept: DateOfMaturity
Original value: 3/15/45
(bx) Concept: DateOfMaturity
Original value: 6/15/25
(by) Concept: DateOfMaturity
Original value: 3/15/46
(bz) Concept: DateOfMaturity
Original value: 3/1/26
(ca) Concept: DateOfMaturity
Original value: 12/1/46
(cb) Concept: DateOfMaturity
Original value: 12/1/2046
(cc) Concept: DateOfMaturity
Original value: 3/15/27
(cd) Concept: DateOfMaturity
Original value: 12/1/27
(ce) Concept: DateOfMaturity
Original value: 12/1/47
(cf) Concept: DateOfMaturity
Original value: 8/1/2023
(cg) Concept: DateOfMaturity
Original value: 8/1/2028
(ch) Concept: DateOfMaturity
Original value: 11/1/26
(ci) Concept: DateOfMaturity
Original value: 11/1/26
(cj) Concept: DateOfMaturity
Original value: Various
(ck) Concept: DateOfMaturity
Original value: 11/1/26
(cl) Concept: DateOfMaturity
Original value: 11/1/26
(cm) Concept: AmortizationPeriodStartDate
Original value: 3/23/04
(cn) Concept: AmortizationPeriodStartDate
Original value: 3/13/07
(co) Concept: AmortizationPeriodStartDate
Original value: 3/3/08
(cp) Concept: AmortizationPeriodStartDate
Original value: 10/21/08
(cq) Concept: AmortizationPeriodStartDate
Original value: 11/18/08
(cr) Concept: AmortizationPeriodStartDate
Original value: 3/6/09
(cs) Concept: AmortizationPeriodStartDate
Original value: 11/18/09
(ct) Concept: AmortizationPeriodStartDate
Original value: 4/1/10
(cu) Concept: AmortizationPeriodStartDate
Original value: 9/15/10
(cv) Concept: AmortizationPeriodStartDate
Original value: 11/18/10
(cw) Concept: AmortizationPeriodStartDate
Original value: 11/18/10
(cx) Concept: AmortizationPeriodStartDate
Original value: 5/13/11
(cy) Concept: AmortizationPeriodStartDate
Original value: 9/12/11
(cz) Concept: AmortizationPeriodStartDate
Original value: 12/1/11
(da) Concept: AmortizationPeriodStartDate
Original value: 4/16/12
(db) Concept: AmortizationPeriodStartDate
Original value: 8/16/12
(dc) Concept: AmortizationPeriodStartDate
Original value: 8/16/12
(dd) Concept: AmortizationPeriodStartDate
Original value: 6/14/13
(de) Concept: AmortizationPeriodStartDate
Original value: 6/14/13
(df) Concept: AmortizationPeriodStartDate
Original value: 11/12/13
(dg) Concept: AmortizationPeriodStartDate
Original value: 11/12/13
(dh) Concept: AmortizationPeriodStartDate
Original value: 2/21/14
(di) Concept: AmortizationPeriodStartDate
Original value: 2/21/14
(dj) Concept: AmortizationPeriodStartDate
Original value: 8/18/14
(dk) Concept: AmortizationPeriodStartDate
Original value: 8/18/14
(dl) Concept: AmortizationPeriodStartDate
Original value: 11/6/14
(dm) Concept: AmortizationPeriodStartDate
Original value: 6/12/15
(dn) Concept: AmortizationPeriodStartDate
Original value: 6/12/15
(do) Concept: AmortizationPeriodStartDate
Original value: 11/5/15
(dp) Concept: AmortizationPeriodStartDate
Original value: 11/5/15
(dq) Concept: AmortizationPeriodStartDate
Original value: 3/1/16
(dr) Concept: AmortizationPeriodStartDate
Original value: 12/1/16
(ds) Concept: AmortizationPeriodStartDate
Original value: 3/10/2017
(dt) Concept: AmortizationPeriodStartDate
Original value: 3/10/17
(du) Concept: AmortizationPeriodStartDate
Original value: 11/29/17
(dv) Concept: AmortizationPeriodStartDate
Original value: 11/29/17
(dw) Concept: AmortizationPeriodStartDate
Original value: 8/6/2018
(dx) Concept: AmortizationPeriodStartDate
Original value: 8/6/2018
(dy) Concept: AmortizationPeriodStartDate
Original value: 5/23/96
(dz) Concept: AmortizationPeriodStartDate
Original value: 9/16/97
(ea) Concept: AmortizationPeriodStartDate
Original value: 6/15/17
(eb) Concept: AmortizationPeriodStartDate
Original value: 9/1/09
(ec) Concept: AmortizationPeriodStartDate
Original value: 6/15/17
(ed) Concept: AmortizationPeriodEndDate
Original value: 3/1/34
(ee) Concept: AmortizationPeriodEndDate
Original value: 3/1/37
(ef) Concept: AmortizationPeriodEndDate
Original value: 2/15/38
(eg) Concept: AmortizationPeriodEndDate
Original value: 10/15/18
(eh) Concept: AmortizationPeriodEndDate
Original value: 10/15/18
(ei) Concept: AmortizationPeriodEndDate
Original value: 3/1/39
(ej) Concept: AmortizationPeriodEndDate
Original value: 1/15/40
(ek) Concept: AmortizationPeriodEndDate
Original value: 3/1/37
(el) Concept: AmortizationPeriodEndDate
Original value: 10/1/20
(em) Concept: AmortizationPeriodEndDate
Original value: 10/1/20
(en) Concept: AmortizationPeriodEndDate
Original value: 1/15/40
(eo) Concept: AmortizationPeriodEndDate
Original value: 5/15/21
(ep) Concept: AmortizationPeriodEndDate
Original value: 9/15/21
(eq) Concept: AmortizationPeriodEndDate
Original value: 12/15/41
(er) Concept: AmortizationPeriodEndDate
Original value: 4/15/42
(es) Concept: AmortizationPeriodEndDate
Original value: 8/16/22
(et) Concept: AmortizationPeriodEndDate
Original value: 8/16/42
(eu) Concept: AmortizationPeriodEndDate
Original value: 6/15/23
(ev) Concept: AmortizationPeriodEndDate
Original value: 6/15/43
(ew) Concept: AmortizationPeriodEndDate
Original value: 11/15/23
(ex) Concept: AmortizationPeriodEndDate
Original value: 11/15/43
(ey) Concept: AmortizationPeriodEndDate
Original value: 2/15/24
(ez) Concept: AmortizationPeriodEndDate
Original value: 2/15/44
(fa) Concept: AmortizationPeriodEndDate
Original value: 8/15/24
(fb) Concept: AmortizationPeriodEndDate
Original value: 2/15/44
(fc) Concept: AmortizationPeriodEndDate
Original value: 3/15/45
(fd) Concept: AmortizationPeriodEndDate
Original value: 6/15/25
(fe) Concept: AmortizationPeriodEndDate
Original value: 3/15/45
(ff) Concept: AmortizationPeriodEndDate
Original value: 6/15/25
(fg) Concept: AmortizationPeriodEndDate
Original value: 3/15/46
(fh) Concept: AmortizationPeriodEndDate
Original value: 3/1/26
(fi) Concept: AmortizationPeriodEndDate
Original value: 12/1/46
(fj) Concept: AmortizationPeriodEndDate
Original value: 12/1/2046
(fk) Concept: AmortizationPeriodEndDate
Original value: 3/15/27
(fl) Concept: AmortizationPeriodEndDate
Original value: 12/1/27
(fm) Concept: AmortizationPeriodEndDate
Original value: 12/1/47
(fn) Concept: AmortizationPeriodEndDate
Original value: 8/1/2023
(fo) Concept: AmortizationPeriodEndDate
Original value: 8/1/2028
(fp) Concept: AmortizationPeriodEndDate
Original value: 11/1/26
(fq) Concept: AmortizationPeriodEndDate
Original value: 11/1/26
(fr) Concept: AmortizationPeriodEndDate
Original value: Various
(fs) Concept: AmortizationPeriodEndDate
Original value: 11/1/26
(ft) Concept: AmortizationPeriodEndDate
Original value: 11/1/26
(fu) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to the repayment of debt in February 2018 (2 months of interest expense).

(fv) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to the repayment of debt in February 2018 (2 months of interest expense).

(fw) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to debt being issued in March 2017 (10 months of interest expense).

(fx) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to debt being issued in March 2017 (10 months of interest expense).

(fy) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to debt being issued in November 2017 (1 month of interest expense).

(fz) Concept: InterestExpenseOnLongTermDebtIssued

Interest expense is different from prior year due to debt being issued in November 2017 (1 month of interest expense).


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL 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 which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
  3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
Line No.
Particulars (Details)
(a)
Amount
(b)
1
Net Income for the Year (Page 117)
6,818,107,469
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
Contributions In Aid of Construction
238,818,033
9
Deductions Recorded on Books Not Deducted for Return
10
Provision for Federal Income Taxes
2,278,988,662
11
Provision for State Income Taxes
1,015,977,063
12
Per attached schedule (See page 261-1)
(a)
13,175,614,895
14
Income Recorded on Books Not Included in Return
15
AFUDC - Equity and debt
181,542,106
16
Balancing Accounts
536,745,233
19
Deductions on Return Not Charged Against Book Income
20
Per attached schedule (See page 261-1)
(b)
2,027,348,975
27
Federal Tax Net Income
555,723,419
28
Show Computation of Tax:
29
Federal Tax Net Income as above $
116,701,918
30
Tax at 21% for Electric, Water. Non-Utility, and Gas
31
Other
32
Add: Tax on FIN 48 Interest
298,573
33
Less: Research & Development Credits
4,187,435
34
Less: Motor Vehicle Credit
750,000
35
Foreign Tax Credit Adjustment Resuting From Specified Liability Losk
4,236,131
36
Utilization of Net Operating Loss Carryover
104,000,477
37
Subtotal Tax
12,298,710
38
FIN 48 Tax Adjustments (Net to Gross)
39
Total Tax
12,298,710
40
Federal Income Tax Accrual
12,298,710


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DeductionsRecordedOnBooksNotDeductedForReturn

 

 

 

 

 

 

 

 

 

 

 

 

 

Annual Report of PACIFIC GAS AND ELECTRIC COMPANY

 

 

 

Year Ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deductions recorded on books not deducted on return:

 

 

Tax addback

 

 

 

 

 

 

 

Executive Compensation

 

 

 

515,207

 

Compensation Related Adjustments

 

 

 

(11,830,175)

 

Penalties

 

 

 

5,334,520

 

NorCal Wildfires Reserve

 

 

 

11,991,045,840

 

Butte Fire Reserve

 

 

 

190,137,035

 

Meals & Entertainment & Lobbying

 

 

 

20,670,644

 

Capitalized Interest

 

 

 

70,563,501

 

Nuclear Fuel expense

 

 

 

125,886,538

 

GHG Allowances

 

 

 

465,459,803

 

DOE Settlement

 

 

 

21,462,460

 

Nuclear Decom Trust Book Expense

 

 

 

49,526,692

 

Loss on Reacquired Debt

 

 

 

3,897,598

 

DCPP Community Payment

 

 

 

134,462,115

 

Depreciation adjustment

 

 

 

107,513,189

 

Other

 

 

 

969,930

 

 

 

 

 

 

 

 

Total

 

$

13,175,614,895

 

 

 

 

 

 

 

 

 

 

 

 

Deductions on return not charged against book income:

Tax deduct

 

 

 

 

 

 

 

Computer Software

 

 

 

(109,723,336)

 

Bad Debts

 

 

 

(8,277,830)

 

Fossil Decommissioning

 

 

 

(20,833,379)

 

Earnings of Subsidiaries

 

 

 

(69,836)

 

Section 263A MSCM

 

 

 

(150,695,799)

 

Repairs

 

 

 

(1,568,837,037)

 

Property Tax & State Income Tax

 

 

 

(74,208,732)

 

Environmental Cleanup

 

 

 

(33,906,984)

 

Gas Hedge Amortization

 

 

 

(12,660,581)

 

Plant Disallowance

 

 

 

(48,135,460)

 

 

 

 

 

 

 

 

Total

 

$

(2,027,348,975)

(b) Concept: DeductionsOnReturnNotChargedAgainstBookIncome

See footnote in row 12, column (b)


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TAXES ACCRUED, PREPAID AND CHARGES DURING YEAR
  1. Give particulars (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 know, 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 proportions of prepaid taxes chargeable 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 then 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 foot- note. 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. Report in columns (l) through (o) how the taxes were distributed. Report in column (o) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (o) the amounts charged to Accounts 408.1 and 409.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (o) the taxes charged to utility plant or other balance sheet accounts.
  9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT BEGINNING OF YEAR BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED
Line No.
DescriptionOfTaxesAccruedPrepaidAndCharged
Kind of Tax (See Instruction 5)
(a)
TypeOfTax
Type of Tax
(b)
TaxJurisdiction
State
(c)
TaxYear
Tax Year
(d)
TaxesAccrued
Taxes Accrued (Account 236)
(e)
PrepaidTaxes
Prepaid Taxes (Include in Account 165)
(f)
TaxesCharged
Taxes Charged During Year
(g)
TaxesPaid
Taxes Paid During Year
(h)
TaxAdjustments
Adjustments
(i)
TaxesAccrued
Taxes Accrued (Account 236)
(j)
PrepaidTaxes
Prepaid Taxes (Included in Account 165)
(k)
TaxesAccruedPrepaidAndCharged
Electric (Account 408.1, 409.1)
(l)
IncomeTaxesExtraordinaryItems
Extraordinary Items (Account 409.3)
(m)
AdjustmentsToRetainedEarnings
Adjustment to Ret. Earnings (Account 439)
(n)
TaxesIncurredOther
Other
(o)
1
Federal - FICA
12,206,965
96,230,144
103,781,479
4,655,630
65,141,285
(e)
31,088,859
2
Federal - Taxes on Income
301,702,762
12,298,710
188,653
(b)
4,236,129
309,576,690
4,236,133
8,062,577
3
Federal - Unemployment
3,874,854
1,077,997
5,007,018
54,167
724,845
353,152
4
Federal - Decommisioning incs
33,367,070
33,367,070
33,367,070
5
SUBTOTAL FEDERAL TAXES
317,784,581
142,973,921
142,344,220
4,236,129
314,178,153
103,469,333
39,504,588
6
State - Taxes on Income
111,930,507
16,339,589
59,269,453
(c)
10,164,738
46,486,203
112,005,442
128,345,031
7
State - Unemployment
90,611
8,068,926
8,053,559
105,978
5,425,546
2,643,380
8
SUBTOTAL STATE TAXES
112,021,118
8,270,663
67,323,012
10,164,738
46,592,181
117,430,988
125,701,651
9
Ad Valorem property
1,103
470,923,474
491,853,474
(d)
20,930,000
1,103
355,073,218
115,850,256
10
(a)
Other
3,589,980
23,184,765
27,047,777
273,032
15,589,436
7,595,329
11
SUBTOTAL OTHER TAXES
3,591,083
494,108,239
518,901,251
20,930,000
271,929
370,662,654
123,445,585
40
TOTAL
433,396,782
360,498,405


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfTaxesAccruedPrepaidAndCharged

Balances primarily includes City and County of San Francisco gross receipts and payroll taxes.

(b) Concept: TaxAdjustments

Adjustment relates to foreign tax credit reflected in column (d)

(c) Concept: TaxAdjustments

Adjustments relates to FIN48

(d) Concept: TaxAdjustments

Adjustment reflects a portion of property taxes paid on construction work in progress. The amount charged during the year was reduced and capitalized to certain assets under construction.

(e) Concept: TaxesIncurredOther

The following table is included to satisfy requirements for Form 1 and Form 2 reporting of this page:

 

 

Gas

(Account 408.1, 409.1)

(a)

Non_utility

(Account 408.2, 409.2)

(b)

Total

Other

(c)

Federal - FICA*

31,088,859

0

31,088,859

Federal - Taxes on Income

1

8,062,576

8,062,577

Federal - Unemployment

353,152

0

353,152

 

 

 

 

 

 

 

 

Total Federal taxes

31,442,012

8,062,576

39,504,588

 

 

 

 

State - Taxes on Income

-98,535,431

-29,809,600

-128,345,031

State - Unemployment

2,643,380

0

2,643,380

 

 

 

 

Total State

-95,892,051

-29,809,600

-125,701,651

 

 

 

 

Ad Valorem property

115,363,512

486,744

115,850,256

Other

7,595,329

0

7,595,329

 

 

 

 

Total Other

122,958,841

486,744

123,445,585

 

*Adjustment reflects a portion of FICA taxes paid on construction work in progress. The amount charged during the year was reduced by the amount capitalized.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)

Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized.

Deferred for Year Allocations to Current Year's Income
Line No.
Account Subdivisions
(a)
Balance at Beginning of Year
(b)
Account No.
(c)
Amount
(d)
Account No.
(e)
Amount
(f)
Adjustments
(g)
Balance at End of Year
(h)
Average Period of Allocation to Income
(i)
ADJUSTMENT EXPLANATION
(j)
1
Electric Utility
2
10%
93,325,105
4,652,206
88,672,899
18
8 TOTAL
93,325,105
4,652,206
88,672,899
9
Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10
10%
20,708,685
997,701
19,710,984
22
11
TOTAL
20,708,685
997,701
19,710,984
48 TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER DEFERRED CREDITS (Account 253)
  1. Report below the particulars (details) called for concerning other deferred credits.
  2. For any deferred credit being amortized, show the period of amortization.
  3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
DEBITS
Line No.
Description and Other Deferred Credits
(a)
Balance at Beginning of Year
(b)
Contra Account
(c)
Amount
(d)
Credits
(e)
Balance at End of Year
(f)
1
(a)
CIAC Deferred Revenue
150,728,145
51,059,826
67,340,832
167,009,151
2
Deferred Cr - Electric Reserves
44,650,027
1,405
2,087,504
46,736,126
3
(b)
Other
12,716,162
18,799,660
19,649,646
13,566,148
47
TOTAL
208,094,334
69,860,891
89,077,982
227,311,425


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfOtherDeferredCredits

Activity includes ~$42 million of amortization. The deferred credit is amortized over 30 years.

(b) Concept: DescriptionOfOtherDeferredCredits

"Other" consists of various other deferred credits amounts with balances of less than 5% of the year end balance (< 227,311,425 * 5% = 11,365,571).


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report


End of:
2018
/
Q4
ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281)
  1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1
Accelerated Amortization (Account 281)
2
Electric
3
Defense Facilities
4
Pollution Control Facilities
5
Other
5.1
Settlement Regulatory Asset
307
307
8
TOTAL Electric (Enter Total of lines 3 thru 7)
307
307
9
Gas
10
Defense Facilities
11
Pollution Control Facilities
12
Other
12.1
Other
12.2
Other
15
TOTAL Gas (Enter Total of lines 10 thru 14)
16
Other
307
16.1
Other
16.2
Other
17
TOTAL (Acct 281) (Total of 8, 15 and 16)
307
307
18
Classification of TOTAL
19
Federal Income Tax
307
307
20
State Income Tax
21
Local Income Tax


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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 rating to property not subject to accelerated amortization.
  2. For other (Specify),include deferrals relating to other income and deductions.
  3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 282
2
Electric
5,866,193,157
567,068,431
246,450,716
(b)
624,198,615
4,921,376,827
3
Gas
1,477,659,791
4,695,705
142,021,557
(c)
1,052,105,146
2,667,090,789
4
Other (Specify)
50,526,203
14,757,291
153,745,799
(a)
166,290,765
385,320,058
5
Total (Total of lines 2 thru 4)
7,394,379,151
571,764,136
388,472,273
14,757,291
153,745,799
166,290,765
427,906,531
7,973,787,674
6
7
8
9
TOTAL Account 282 (Total of Lines 5 thru 8)
7,394,379,151
571,764,136
388,472,273
14,757,291
153,745,799
166,290,765
427,906,531
7,973,787,674
10
Classification of TOTAL
11
Federal Income Tax
5,790,140,411
503,086,946
260,939,801
10,113,424
153,512,599
175,076,548
332,934,582
6,219,630,419
12
State Income Tax
1,604,238,740
68,677,189
127,532,472
4,643,867
233,200
8,785,783
94,971,948
1,754,157,255
13
Local Income Tax


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherPropertyAdjustmentsDebitedToAccount

SFAS 109 adjustment and excess deferreds adjustment due to the fed rate change - account 254.

(b) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherPropertyAdjustmentsCreditedToAccount

SFAS 109 adjustment and excess deferreds adjustment due to the fed rate change - account 254.

(c) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherPropertyAdjustmentsCreditedToAccount

SFAS 109 adjustment and excess deferreds adjustment due to the fed rate change - account 254.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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. For other (Specify),include deferrals relating to other income and deductions.
  3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
  4. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Debits Credits
Line No.
Account
(a)
Balance at Beginning of Year
(b)
Amounts Debited to Account 410.1
(c)
Amounts Credited to Account 411.1
(d)
Amounts Debited to Account 410.2
(e)
Amounts Credited to Account 411.2
(f)
Account Credited
(g)
Amount
(h)
Account Debited
(i)
Amount
(j)
Balance at End of Year
(k)
1 Account 283
2
Electric
3
Loss on Reacquired Debt
46,351,590
17,583,231
29,197,869
34,736,952
4
Balancing Accounts
142,447,428
25,734,058
81,541,543
(a)
102,489,643
352,212,672
5
Other
2,495,951
1,741,064
14,529,089
18,766,104
9 TOTAL Electric (Total of lines 3 thru 8)
191,294,969
45,058,353
66,872,763
102,489,643
405,715,728
10
Gas
11
Loss on Reacquired Debt
21,963,589
5,789,837
11,015,454
16,737,972
12
Balancing Accounts
268,468,323
23,957,685
99,713,602
25,112,667
217,825,073
13
Other
2,161,432
597,013
98,562
1,662,981
17 TOTAL Gas (Total of lines 11 thru 16)
288,270,480
30,344,535
110,827,618
25,112,667
232,900,064
18 TOTAL Other
31,348,386
11,307,727
1,458,408
21,499,067
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
448,217,063
75,402,888
43,954,855
11,307,727
1,458,408
127,602,310
(b)
617,116,725
20
Classification of TOTAL
21
Federal Income Tax
393,514,962
20,436,820
40,112,798
11,310,245
1,458,408
41,843,093
425,533,914
22
State Income Tax
54,702,101
54,966,068
3,842,057
2,518
85,759,217
191,582,811
23
Local Income Tax
NOTES


FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxLiabilitiesOtherAdjustmentsCreditedToAccount

 

FERC Form 1 Pages 276-277

Dec. 31, 2018

 

 

Detail of Adjustments

 

Debit (Credit)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

[A]

(102,489,643)

Excess deferred adjustments due to change in fed tax rate - account 254

 

 

 

 

 

 

[B]

(25,112,667)

Excess deferred adjustments due to change in fed tax rate - account 254

(b) Concept: AccumulatedDeferredIncomeTaxesOther

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
OTHER REGULATORY LIABILITIES (Account 254)
  1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
  2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped by classes.
  3. For Regulatory Liabilities being amortized, show period of amortization.
DEBITS
Line No.
Description and Purpose of Other Regulatory Liabilities
(a)
Balance at Beginning of Current Quarter/Year
(b)
Account Credited
(c)
Amount
(d)
Credits
(e)
Balance at End of Current Quarter/Year
(f)
1
CA Energy Systems 21st Centur B/A Elect NC
308,024
3,536,524
3,460,596
383,952
2
(amortization: 5 years)
3
California Solar Initiative
66,414,573
14,016,129
9,220,917
61,619,361
4
(amortization: 5 years)
5
Demand Response Expenditures Balancing Account
57,642,744
69,069,154
51,492,499
40,066,089
6
Distribution Resource Plan Demo B/A Curr
107,978
235,686
1,067,647
939,939
7
(amortization: <12 months)
8
DREBA Operations Balancing Account - Current
24,840,637
25,169,788
12,458,361
12,129,210
9
Electric Vehicle Program BA Current
1,972,297
13,432,047
18,915,509
3,511,165
10
(amortization: <12 months)
11
Electric Price Risk Management - Current
26,867,115
104,655,510
120,740,007
42,951,612
12
Electric Price Risk Management - NonCurrent
101,500,411
375,684,882
439,345,727
165,161,256
13
Electric Program Investment Charge Balancing Acct
173,193,908
90,142,787
106,454,386
189,505,507
14
Engineering Critical Assessment Bal ACCT-CURRENT
9,848,830
73,668,433
63,819,603
15
(amortization: <12 months)
16
FAS 109 Reg Liability
1,020,833,435
5,397,386,422
4,660,041,025
283,488,038
17
(amortization: >12 months)
18
FAS 143 Regulatory Liability - Nuclear
(a)
999,999,999
(e)
999,999,999
19
FAS 143 Regulatory Liability - Nuclear
574,459,931
254,460,135
136,957,777
691,962,289
20
FAS 143 Regulatory Liability - Fossil
132,024,941
13,861,210
145,886,151
21
FAS 143 Regulatory Liability - Fossil Decomm
176,633,546
7,769,312
168,864,234
22
FAS 143 Regulatory Liability-Nuclear Decomm
2,863,247,225
588,388,705
454,862,836
2,729,721,356
23
FIN 47 Regulatory Liability
709,047,472
580,609,698
584,794,371
704,862,799
24
Gas PPP Surcharge-RDD
398,165
12,095,232
12,058,377
435,020
25
(amortization: <12 months)
26
Gas Price Risk Management - Current
376,079
9,427,335
9,504,259
453,003
27
GHGRBA - Greenhouse Gas Revenue Subaccount
89,838,359
464,936,605
348,977,027
26,121,219
28
(amortization: <12 months)
29
GHGRBA - Low Carbon Fuels Stnd Rev Subaccount
18,626,564
17,572,385
61,611,607
62,665,786
30
(amortization: <12 months)
31
GPBA - Greenhouse Gas Revenue Subaccount
222,829,867
331,869,052
109,298,352
259,167
32
(amortization: <12 months)
33
GPBA - Low Carbon Fuels Stnd Rev Subaccount
685,998
443,920
391,047
633,125
34
(amortization: <12 months)
35
Miscellaneous Electric Reg Liab - Current
80,613,478
99,581,295
343,955,376
324,987,559
36
(amortization: <12 months)
37
Miscellaneous Electric Reg Liab - NonCurrent
245,025,521
50,428,889
355,395,957
549,992,589
38
MISCELLANEOUS GAS REG LIAB - CURRENT
9
61,085,215
101,987,163
40,901,957
39
Amortization : <12 MONTHS
40
MISCELLANEOUS GAS REG LIAB - NONCURRENT
19,026,468
6,158,348
3,382,670
16,250,790
41
Amortization : 2 YEARS
42
NATIONAL GAS LEAK ABATEMENT PROGRAM BALANCING ACT
1,145,007
2,166,870
1,021,863
43
(amortization: < 12 months)
44
NON CURRENT REG LIAB-CC8 SETTLEMENT
46,856,179
2,260,506
44,595,673
45
(amortization: < 12 months)
46
Amortization : 25 YEARS
47
NON-TARIFFED PRODUCTS AND SVCS BA-ELECTRIC
321,567
2,434,436
2,688,612
575,743
48
Amortization : < 12 MONTHS
49
NON-TARIFFED PRODUCTS AND SVCS BA-GAS
262,995
304,707
511,842
470,130
50
Amortization : < 12 MONTHS
51
ON BILL FINANCING BALANCING ELECTRIC
44,053,920
13,595,803
12,413,062
42,871,179
52
ON BILL FINANCING BALANCING GAS
9,541,493
2,589,677
2,387,522
9,339,338
53
PPP (PPPLIBA)-ELECTRIC
161,760,083
77,081,759
88,351,838
173,030,162
54
Amortization : < 12 MONTHS
55
PPP (PPPLIBA)-GAS
57,115,769
59,190,195
79,331,373
77,256,947
56
Amortization : < 12 MONTHS
57
PPP ENERGY EFFICIENCY-GAS
3,523,260
1,368,582
329,218
2,483,896
58
PPP SURCHARGE ENERGY EFFICIENCY - GAS
6,165,082
97,896,209
90,617,259
1,113,868
59
Amortization : < 12 MONTHS
60
PPP SURCHARGE LOW INCOME - GAS
8,697,021
79,311,319
80,449,644
7,558,696
61
Amortization : < 12 MONTHS
62
PPP SURCHARGE RDD - CURRENT
3,589,636
11,069,274
11,097,731
3,618,093
63
Amortization : < 12 MONTHS
64
PROCUREMENT ENERGY EFFICIENCY
15,108,043
6,234,784
1,480,986
10,354,245
65
PROCUREMENT ENERGY EFFICIENCY BALANCING ACCT - CT
121,365,565
363,403,980
447,494,954
205,456,539
66
Amortization : <12 MONTHS
67
PUBL PURP PROG ENERGY EFFICIENCY BAL ACCT - CURRT
24,615,780
78,711,291
94,747,059
40,651,548
68
Amortization : <12 MONTHS
69
REG LIABILITY GAS RISK MGMT - NONCURRENT
629,984
797,660
306,342
138,666
70
REG LIABILITY-MISC ELEC CURRENT -FERC INTEREST BG
1,686
74,837,561
74,835,875
71
Amortization : <12 MONTHS
72
REGULATORY LIABILITY RETIREM
418,061,715
34,704,994
37,298,481
420,655,202
73
Amortization : INDEFINITE
74
RULE 20A BALANCING ACCOUNT (RBA) NONCURRENT
18,110,041
11,472,486
6,637,555
75
Amortization : > 12 MONTHS
76
SELF GENERATION PROGARM-GAS
35,020,030
5,040,192
13,822,471
43,802,309
77
SELF GENERATION PROGRAM - ELECTRIC
180,387,537
22,960,873
63,388,316
220,814,980
78
SOLAR ON MULTIFAMILY AFFORDABLE HOUSING BAL ACCT
51,081,839
51,081,839
79
Amortization : < 12 MONTHS
80
SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA
4,349,169
14,652,489
11,904,138
1,600,818
81
Amortization : < 12 MONTHS
82
SW MARKETING, EDUCATION AND OUTREACH PROGRAM BA
755,732
1,620,822
1,321,828
456,738
83
Amortization : < 12 MONTHS
84
TAMA - GAS
64,490,315
36,799,024
101,289,339
85
Amortization : 2 YEARS
86
Miscellanous minor items
45,716,209
1,237,268,178
1,191,551,974
5
41 TOTAL
3,876,105,498
10,770,418,583
10,391,095,332
(f)
3,496,782,247


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OtherRegulatoryLiabilities

The FERC software will not allow the entire beginning balance of FAS 143 Regulatory Liability of ($1,574,459,929) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 18: ($999,999,999)

Line 19: ($574,459,930)

Total ($1,574,459,929)

(b) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Offset to account 108 - Accumulated Depreciation, and 230 - ARO - Liability.

(c) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Offset to account 108 - Accumulated Depreciation, and 230 - ARO - Liability.

(d) Concept: OtherRegulatoryLiabilitiesDescriptionOfCreditedAccountNumberForDebitAdjustment

Activity primarily related to SH FUNDED GAS TRANS SAFETY ACCOUNT offset to 182.3

(e) Concept: OtherRegulatoryLiabilities

The FERC software will not allow the entire ending balance of FAS 143 Regulatory Liability of ($1,691,962,287) to be shown, as it is too large. As such, the balance has been broken into the following:

 

Line 18: ($999,999,999)

Line 19: ($691,962,288)

Total ($1,691,962,287)

(f) Concept: OtherRegulatoryLiabilities

See page 122-123 for details on the remeasurement of excess deferred income taxes in 2017, as a result of teh Tax Cuts and Jobs Act of 2017.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Electric Operating Revenues
  1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages.
  2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
  3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month.
  4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
  5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
  6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.)
  7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
  8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
  9. Include unmetered sales. Provide details of such Sales in a footnote.
Line No.
Title of Account
(a)
Operating Revenues Year to Date Quarterly/Annual
(b)
Operating Revenues Previous year (no Quarterly)
(c)
MEGAWATT HOURS SOLD Year to Date Quarterly/Annual
(d)
MEGAWATT HOURS SOLD Amount Previous year (no Quarterly)
(e)
AVG.NO. CUSTOMERS PER MONTH Current Year (no Quarterly)
(f)
AVG.NO. CUSTOMERS PER MONTH Previous Year (no Quarterly)
(g)
1
SalesOfElectricityHeadingAbstract
Sales of Electricity
2
ResidentialSalesAbstract
(440) Residential Sales
5,051,462,029
5,693,009,418
27,485,186
29,408,850
4,798,731
4,808,753
3
CommercialAndIndustrialSalesAbstract
(442) Commercial and Industrial Sales
4
CommercialSalesAbstract
Small (or Comm.) (See Instr. 4)
(a)
6,141,452,151
(f)
6,499,737,292
36,430,669
36,881,436
635,503
634,978
5
IndustrialSalesAbstract
Large (or Ind.) (See Instr. 4)
(b)
1,531,576,710
(g)
1,603,479,860
15,163,358
15,187,122
1,314
1,325
6
PublicStreetAndHighwayLightingAbstract
(444) Public Street and Highway Lighting
63,885,241
69,800,620
306,682
327,380
36,204
34,795
7
OtherSalesToPublicAuthoritiesAbstract
(445) Other Sales to Public Authorities
2,263,228
2,175,010
12,790
12,177
2
13
8
SalesToRailroadsAndRailwaysAbstract
(446) Sales to Railroads and Railways
6,151,562
6,988,161
377,019
407,351
23
25
9
InterdepartmentalSalesAbstract
(448) Interdepartmental Sales
46,634,494
44,421,522
290,560
289,607
10
SalesToUltimateConsumersAbstract
TOTAL Sales to Ultimate Consumers
(c)
12,843,425,415
(h)
13,919,611,883
(k)(l)(m)
80,066,264
82,513,923
5,471,777
5,479,889
11
SalesForResaleAbstract
(447) Sales for Resale
326,502,665
112,554,619
10,790,942
5,661,727
12
SalesOfElectricityAbstract
TOTAL Sales of Electricity
13,169,928,080
14,032,166,502
90,857,206
88,175,650
5,471,777
5,479,889
13
ProvisionForRateRefundsAbstract
(Less) (449.1) Provision for Rate Refunds
580,325,469
169,512,710
14
RevenuesNetOfProvisionForRefundsAbstract
TOTAL Revenues Net of Prov. for Refunds
12,589,602,611
13,862,653,792
90,857,206
88,175,650
5,471,777
5,479,889
15
OtherOperatingRevenuesAbstract
Other Operating Revenues
16
ForfeitedDiscounts
(450) Forfeited Discounts
4,139,504
5,496,959
17
MiscellaneousServiceRevenues
(451) Miscellaneous Service Revenues
(d)
9,362,424
(i)
9,650,326
18
SalesOfWaterAndWaterPower
(453) Sales of Water and Water Power
3,683,870
3,621,831
19
RentFromElectricProperty
(454) Rent from Electric Property
104,364,515
86,527,942
20
InterdepartmentalRents
(455) Interdepartmental Rents
21
OtherElectricRevenue
(456) Other Electric Revenues
(e)
262,517,205
(j)
343,369,626
22
RevenuesFromTransmissionOfElectricityOfOthers
(456.1) Revenues from Transmission of Electricity of Others
1,845,837
2,830,782
23
RegionalTransmissionServiceRevenues
(457.1) Regional Control Service Revenues
24
MiscellaneousRevenue
(457.2) Miscellaneous Revenues
25
OtherMiscellaneousOperatingRevenues
Other Miscellaneous Operating Revenues
25.1
OtherMiscellaneousOperatingRevenues
(400) Balancing Accounts
635,580,851
343,783,254
26
OtherOperatingRevenues
TOTAL Other Operating Revenues
496,459,796
579,025,040
27
ElectricOperatingRevenues
TOTAL Electric Operating Revenues
13,086,062,407
13,283,628,752


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SmallOrCommercialSalesElectricOperatingRevenue

Line 4 includes all other commercial and industrial customers including irrigation pumping.

(b) Concept: LargeOrIndustrialSalesElectricOperatingRevenue

Line 5 includes commercial and industrial customers with demands of 1,000 Kw or greater.

(c) Concept: SalesToUltimateConsumers

Column (b) includes California Department of Water Resources ("DWR") revenues of $410,485,871 which was deducted from Line 21 below.

(d) Concept: MiscellaneousServiceRevenues

 

This consists of :

 

1

NSF fees and rent charges to customers' refundable deposits

1,510,591

2

NRD Revenue

2,501,467

3

MLX billings to electric residential customers

3,271,478

4

MLX billings to electric non-residential customers

927,612

5

Reimbursable third-party labor requested on behalf of customers

1,151,276

 

 

 

 

Total

9,362,424

(e) Concept: OtherElectricRevenue

 

This consists of :

 

Unbilled revenues

(1,586,893)

Reimbursement to the Utility for costs spent on customer projects

26,889,727

Reimbursement to the Utility for costs spent on customer billing

7,448,792

Reimbursement fees paid to the CPUC based on sales

(36,570,942)

Employee transfer fees

341,127

Other revenue-damage claim

2,321,285

Recreational Facilities Revenue

1,402,622

Revenue assigned - base

(23,988,441)

Pass-through franchise fees and uncollectible revenue

23,988,441

Transition Cost Revenue Account for non-bypassable charges

38,531,280

Fees for utility energy service contracts

51,290,247

Other electric revenues not classified elsewhere

57,148,118

MCI rights of way

691,661

DWR

(410,485,871)

Miscellaneous (items under $250,000)

61,641

 

 

Total

(262,517,206)

 

The DWR revenues of $410,485,871 represents amount passed through to the DWR. The Utility acts as a pass-through entity for DWR charges collected from the Utility's customers. Although charges for the DWR are included in total electric revenues, the Utility deducts pass through amounts from electric revenues. These pass-through revenues are excluded from the Utility's electric revenues in its Statement of Income.

(f) Concept: SmallOrCommercialSalesElectricOperatingRevenue

Line 4 includes all other commercial and industrial customers including irrigation pumping.

(g) Concept: LargeOrIndustrialSalesElectricOperatingRevenue

Line 5 includes commercial and industrial customers with demands of 1,000 Kw or greater.

(h) Concept: SalesToUltimateConsumers

Column (b) includes California Department of Water Resources ("DWR") revenues of $315,481,524 which was deducted from Line 21 below.

(i) Concept: MiscellaneousServiceRevenues

 

This consists of :

 

NSF fees and rent charges to customers' refundable deposits

1,682,640

NRD Revenue

2,746,217

MLX billings to electric residential customers

3,199,430

MLX billings to electric non-residential customers

1,024,123

Reimbursable third-party labor requested on behalf of customers

997,916

 

 

Total

9,650,326

(j) Concept: OtherElectricRevenue

 

This consists of :

 

Unbilled revenues

(75,837,834)

Reimbursement to the Utility for costs spent on customer projects

50,772,932

Reimbursement to the Utility for costs spent on customer billing

5,342,943

Reimbursement fees paid to the CPUC based on sales

(34,903,166)

Employee transfer fees

2,649,724

Other revenue-damage claim

1,699,240

Recreational Facilities Revenue

1,249,347

Revenue assigned - base

(21,785,055)

Pass-through franchise fees and uncollectible revenue

21,785,055

Transition Cost Revenue Account for non-bypassable charges

33,987,442

Fees for utility energy service contracts

29,088,601

Other electric revenues not classified elsewhere

52,392,084

MCI rights of way

691,661

DWR

(410,341,937)

Miscellaneous (items under $250,000)

117,981

 

 

Total

(343,090,982)

 

The DWR revenues of $410,341,937 represents amount passed through to the DWR. The Utility acts as a pass-through entity for DWR charges collected from the Utility's customers. Although charges for the DWR are included in total electric revenues, the Utility deducts pass through amounts from electric revenues. These pass-through revenues are excluded from the Utility's electric revenues in its Statement of Income.

(k) Concept: MegawattHoursSoldSalesToUltimateConsumers

This includes MWH sales for DWR and DA as discussed in the footnote to Line 10, column b.

(l) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 49516473
(m) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1)
  1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.
Line No.
Description of Service
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1
NONE
46
TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
  1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
  2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading.
  3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers.
  4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly).
  5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
  6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
Line No.
Number and Title of Rate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number of Customers
(d)
KWh of Sales Per Customer
(e)
Revenue Per KWh Sold
(f)
1
440 Residential Sales:
2
E1 Individually Metered
17,536,596
3,579,290,436
1,013
583,917
0.2041
3
EL1 Residential Care Program S
6,516,017
811,459,315
1,013
583,917
0.1245
4
E6 Residential Time-of-Use Servic
413,028
85,107,830
1,013
583,917
0.2061
5
EL6 Residential Care Time-of-U
34,294
4,244,198
1,013
583,917
0.1238
6
E7 Time-of-Use
22
3,366
1,013
583,917
0.153
7
EL7 Residential Care Program T
2
8
E8 Seasonal Service Option
151
43,600
1,013
583,917
0.2887
9
EL8 Residential Seasonal Care
20
3,490
0.1745
10
ETOUA Residential Time-of-Use Ser
436,367
98,086,586
1,013
583,917
0.2248
11
EL-TOUA Residential Care Time-of-
77,881
9,086,571
1,013
583,917
0.1167
12
ETOUB Residential Time-of-Use Ser
614,416
135,391,113
1,013
583,917
0.2204
13
EL-TOUB Residential Care Time-of-
88,230
11,543,587
1,013
583,917
0.1308
14
ETOUC Residential Time-of-Use Ser
400,015
93,699,020
1,013
583,917
0.2342
15
EL-TOUC Residential Care Time-of-
48,514
5,983,417
1,013
583,917
0.1233
16
ETOUP Residential Time-of-Use Ser
1
63
0.063
17
EA9 Experimental TOU Service for
18
EB9 Experimental TOU Service for
18
19
ECLSD
752
20
EVA Residential TOU Service for P
644,051
112,516,469
1,013
583,917
0.1747
21
EVB Residential TOU Service for P
1,308
189,092
1,013
583,917
0.1446
22
EM Master-Metered Multi-family Se
211,513
39,491,286
1,013
583,917
0.1867
23
EML Multifamily CARE Program - Ma
26,273
3,049,414
1,013
583,917
0.1161
24
EMTOU Residential Time of Use Ser
1,079
448,975
1,013
583,917
0.4161
25
ES Multi-family Service
24,341
3,811,479
1,013
583,917
0.1566
26
ESL Multifamily CARE Program Serv
26,656
3,821,936
1,013
583,917
0.1434
27
ESR RV Park and Residential Marin
1,810
325,544
1,013
583,917
0.1799
28
ESRL RV Park and Residential Mari
8,702
1,358,660
1,013
583,917
0.1561
29
ET Mobilehome Park Service
14,344
2,157,266
1,013
583,917
0.1504
30
ETL Low-Income Mobile Home
357,532
50,007,682
1,013
583,917
0.1399
31
MIS-RS
44
18
0.0004
32
SE1 Standby - Individually Metere
107
23,706
1,013
583,917
0.2216
33
SEM1 Standby - Master-Metered Mul
2,260
361,345
1,013
583,917
0.1599
34
STOUS Standby - TOU Secondary - I
56,745
1,013
35
UNCLASSIFIED
36
Total Residential
27,485,186
5,051,462,029
1,013
583,917
0.1838
37
442 Commercial and Industrial Sal
38
A1 Small General Service
1,062,816
195,948,995
1,013
583,917
0.1844
39
A1F Small General Service
71,322
15,595,784
1,013
583,917
0.2187
40
A1X Small General Service
5,651,396
1,166,006,444
1,013
583,917
0.2063
41
A15 Small General Service
446
247,635
1,013
583,917
0.5552
42
A6 Time-of-Use
1,339,517
260,231,066
1,013
583,917
0.1943
43
A10 Medium General Demand-Metered
8,431,271
1,449,532,884
1,013
583,917
0.1719
44
E19 500 to 999 Kw Demand
13,389,196
1,780,218,556
1,013
583,917
0.133
45
E20 1000 Kw Demand or More
13,229,175
1,300,572,321
1,013
583,917
0.0983
46
E37 1000 Kw Demand or More
24,413
2,813,007
1,013
583,917
0.1152
47
AG1 Agricultural Power
78,531
22,137,091
1,013
583,917
0.2819
48
AG4 TOU Agricultural Power
1,244,290
339,525,584
1,013
583,917
0.2729
49
AG5 Large TOU Agricultural Power
4,871,556
853,210,492
1,013
583,917
0.1751
50
AGICE Agricultural Internal Combu
5,249
702,053
1,013
583,917
0.1337
51
AGR Split-Wk TOU Agricultural Pow
38,611
10,469,135
1,013
583,917
0.2711
52
AGV Short-Pk TOU Agricultural Pow
31,230
7,743,085
1,013
583,917
0.2479
53
MIS-RS
4
3,029
0.7573
54
OL1 Outdoor Area Lighting Service
8,978
2,649,296
1,013
583,917
0.2951
55
SA1 Standby & General Service
88
20,618
1,013
583,917
0.2343
56
SA6 Standby & Small TOU
8,111
1,397,130
1,013
583,917
0.1723
57
SA10 Standby & Alt. Rate for Med-
14,014
2,043,821
1,013
583,917
0.1458
58
SE19 Standby & 500 to 999 Kw Dema
108,088
16,702,169
1,013
583,917
0.1545
59
SE20 Standby & 1000 Kw Demand or
1,543,627
166,833,988
1,013
583,917
0.1081
60
SE37 Standby - Med Gen Demand-Mtr
25,004
3,273,616
1,013
583,917
0.1309
61
STOUP Standby - TOU Primary
16,379
10,474,652
1,013
583,917
0.6395
62
STOUS Standby - TOU Secondary - I
2,091
2,469,785
1,013
583,917
1.1812
63
STOUT Standby - TOU Transformer
413,987
62,152,276
1,013
583,917
0.1501
64
UNCLASSIFIED
859
60,407
1,013
583,917
0.0703
65
Total Commercial and Industrial
51,594,027
7,673,028,861
1,013
583,917
0.1487
66
444 Public Street and Highway Lig
67
LS1-A Utility-Owned Street & High
13,501
8,198,329
1,013
583,917
0.6072
68
LS1-B Utility-Owned Street & High
27
7,016
1,013
583,917
0.2599
69
LS1-C Utility-Owned Street & High
4,548
2,686,673
1,013
583,917
0.5907
70
LS1-D Utility-Owned Street & High
7,777
3,341,493
1,013
583,917
0.4297
71
LS1-E Utility-Owned Street & High
9,129
8,001,758
1,013
583,917
0.8765
72
LS1-F Utility-Owned Street & High
4,368
2,529,399
1,013
583,917
0.5791
73
LS2-A Customer-Owned Street & Hig
214,319
29,083,083
1,013
583,917
0.1357
74
LS2-C Customer-Owned Street & Hig
1,945
457,139
1,013
583,917
0.235
75
LS3 Cust-Owned Street & Highway L
7,915
1,134,781
1,013
583,917
0.1434
76
LS3-F Cust-Owned Street & Highway
4,017
663,555
1,013
583,917
0.1652
77
TC1 Traffic Control Service
37,945
7,531,226
1,013
583,917
0.1985
78
TC1F Traffic Control Service
1,191
250,789
1,013
583,917
0.2106
79
Total Public Street and Highway
306,682
63,885,241
1,013
583,917
0.2083
80
445 Other Sales to Public Authori
81
Special Contracts
12,790
2,263,228
1,013
583,917
0.177
82
Total Other Sales to Public Aut
12,790
2,263,228
1,013
583,917
0.177
83
446 Sales to Railroads and Railwa
84
Special Contracts
377,019
6,151,562
1,013
583,917
0.0163
85
Total Sales to Railroads and Ra
377,019
6,151,562
1,013
583,917
0.0163
86
448 Interdepartmental Sales
290,560
46,634,494
0.1605
87
Total Interdepartmental Sales
290,560
46,634,494
0.1605
88
Total Sales to
89
Ultimate Consumers
90
447 Sales for Resale
91
Special Contracts
326,502,665
41 TOTAL Billed - All Accounts
80,066,264
13,169,928,080
5,471,777
14,633
0.1645
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43 TOTAL - All Accounts
80,066,264
13,169,928,080
5,471,777
14,633
0.1645


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
SALES FOR RESALE (Account 447)
  1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327).
  2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers.

    LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years.

    SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less.

    LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

    OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote.

    AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (g) through (k).
  5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided.
  6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
  8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser.
  9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,line 24.
  10. Footnote entries as required and provide explanations following all required data.
ACTUAL DEMAND (MW) REVENUE
Line No.
Name of Company or Public Authority (Footnote Affiliations)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Average Monthly Billing Demand (MW)
(d)
Average Monthly NCP Demand
(e)
Average Monthly CP Demand
(f)
Megawatt Hours Sold
(g)
Demand Charges ($)
(h)
Energy Charges ($)
(i)
Other Charges ($)
(j)
Total ($) (h+i+j)
(k)
1
RQ Sales:
2
(a)
Silicon Valley Power
0.4
17.7
17.7
1,843
1,071
39,544
40,615
3
0.0
0.0
0.0
4
(c)
California Independent System Operator
10,789,099
344,976,739
18,514,689
326,462,050
15
Subtotal - RQ
(g)
10,790,942
1,071
345,016,283
18,514,689
326,502,665
16
Subtotal-Non-RQ
17 Total
10,790,942
1,071
345,016,283
18,514,689
326,502,665


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale
  • Sales represent the Grizzly Power Sale.

  • Silicon Valley Power was formally the City of Santa Clara.

  • The Rate Schedule for Grizzly was changed in FERC Docket No. ER17-1752-000.

(b) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

 

The ETC between PG&E and CCSF terminated on July 1, 2015, pursuant to Section 9.26.2 of the CCSF Interconnection Agreement (IA), Rate Schedule FERC No. 114.

(c) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

Represents amounts included in ISO Settlement Statement on page 397.

(d) Concept: AverageMonthlyBillingDemand
Original value: N/A
(e) Concept: AverageMonthlyNonCoincidentPeakDemand
Original value: N/A
(f) Concept: AverageMonthlyCoincidentPeakDemand
Original value: N/A
(g) Concept: MegawattHoursSoldRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 23, Column: b, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES

If the amount for previous year is not derived from previously reported figures, explain in footnote.

Line No.
Account
(a)
Amount for Current Year
(b)
Amount for Previous Year (c)
(c)
1
PowerProductionExpensesAbstract
1. POWER PRODUCTION EXPENSES
2
SteamPowerGenerationAbstract
A. Steam Power Generation
3
SteamPowerGenerationOperationAbstract
Operation
4
OperationSupervisionAndEngineeringSteamPowerGeneration
(500) Operation Supervision and Engineering
55,323
1,413
5
FuelSteamPowerGeneration
(501) Fuel
207,064,898
176,832,878
6
SteamExpensesSteamPowerGeneration
(502) Steam Expenses
16,174
10,249
7
SteamFromOtherSources
(503) Steam from Other Sources
8
SteamTransferredCredit
(Less) (504) Steam Transferred-Cr.
9
ElectricExpensesSteamPowerGeneration
(505) Electric Expenses
10
MiscellaneousSteamPowerExpenses
(506) Miscellaneous Steam Power Expenses
388,314
651,480
11
RentsSteamPowerGeneration
(507) Rents
12
Allowances
(509) Allowances
35,626,112
27,272,848
13
SteamPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 4 thru 12)
243,150,821
204,768,868
14
SteamPowerGenerationMaintenanceAbstract
Maintenance
15
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
(510) Maintenance Supervision and Engineering
129,982
17,771
16
MaintenanceOfStructuresSteamPowerGeneration
(511) Maintenance of Structures
17
MaintenanceOfBoilerPlantSteamPowerGeneration
(512) Maintenance of Boiler Plant
1,478,290
1,669,805
18
MaintenanceOfElectricPlantSteamPowerGeneration
(513) Maintenance of Electric Plant
19,232,845
11,150,358
19
MaintenanceOfMiscellaneousSteamPlant
(514) Maintenance of Miscellaneous Steam Plant
1,691,099
4,324,333
20
SteamPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 15 thru 19)
22,532,216
5,138,449
21
PowerProductionExpensesSteamPower
TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
265,683,037
199,630,419
22
NuclearPowerGenerationAbstract
B. Nuclear Power Generation
23
NuclearPowerGenerationOperationAbstract
Operation
24
OperationSupervisionAndEngineeringNuclearPowerGeneration
(517) Operation Supervision and Engineering
4,025,966
6,147,760
25
NuclearFuelExpense
(518) Fuel
129,114,087
124,868,867
26
CoolantsAndWater
(519) Coolants and Water
37,292,499
30,611,193
27
SteamExpensesNuclearPowerGeneration
(520) Steam Expenses
38,815,499
38,190,638
28
SteamFromOtherSourcesNuclearPowerGeneration
(521) Steam from Other Sources
29
SteamTransferredCreditNuclearPowerGeneration
(Less) (522) Steam Transferred-Cr.
30
ElectricExpensesNuclearPowerGeneration
(523) Electric Expenses
1,867,685
1,998,438
31
MiscellaneousNuclearPowerExpenses
(524) Miscellaneous Nuclear Power Expenses
338,894,022
164,674,710
32
RentsNuclearPowerGeneration
(525) Rents
33
NuclearPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of lines 24 thru 32)
550,009,758
366,491,606
34
NuclearPowerGenerationMaintenanceAbstract
Maintenance
35
MaintenanceSupervisionAndEngineeringNuclearPowerGeneration
(528) Maintenance Supervision and Engineering
2,782,594
3,239,200
36
MaintenanceOfStructuresNuclearPowerGeneration
(529) Maintenance of Structures
3,442,055
1,104,975
37
MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration
(530) Maintenance of Reactor Plant Equipment
26,816,759
29,240,710
38
MaintenanceOfElectricPlantNuclearPowerGeneration
(531) Maintenance of Electric Plant
36,172,375
42,948,466
39
MaintenanceOfMiscellaneousNuclearPlant
(532) Maintenance of Miscellaneous Nuclear Plant
83,619,837
57,119,138
40
NuclearPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 35 thru 39)
14,406,054
133,652,489
41
PowerProductionExpensesNuclearPower
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
535,603,704
500,144,095
42
HydraulicPowerGenerationAbstract
C. Hydraulic Power Generation
43
HydraulicPowerGenerationOperationAbstract
Operation
44
OperationSupervisionAndEngineeringHydraulicPowerGeneration
(535) Operation Supervision and Engineering
448,001
2,199,949
45
WaterForPower
(536) Water for Power
2,190,879
2,128,801
46
HydraulicExpenses
(537) Hydraulic Expenses
1,449,339
1,317,581
47
ElectricExpensesHydraulicPowerGeneration
(538) Electric Expenses
26,715,623
29,079,473
48
MiscellaneousHydraulicPowerGenerationExpenses
(539) Miscellaneous Hydraulic Power Generation Expenses
60,364,066
65,379,284
49
RentsHydraulicPowerGeneration
(540) Rents
796,739
785,420
50
HydraulicPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 44 thru 49)
91,964,647
100,890,508
51
HydraulicPowerGenerationContinuedAbstract
C. Hydraulic Power Generation (Continued)
52
HydraulicPowerGenerationMaintenanceAbstract
Maintenance
53
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
(541) Mainentance Supervision and Engineering
1,648,157
2,542,935
54
MaintenanceOfStructuresHydraulicPowerGeneration
(542) Maintenance of Structures
2,122,736
5,802,047
55
MaintenanceOfReservoirsDamsAndWaterways
(543) Maintenance of Reservoirs, Dams, and Waterways
23,269,718
35,462,156
56
MaintenanceOfElectricPlantHydraulicPowerGeneration
(544) Maintenance of Electric Plant
19,942,182
21,197,455
57
MaintenanceOfMiscellaneousHydraulicPlant
(545) Maintenance of Miscellaneous Hydraulic Plant
5,923,153
8,679,202
58
HydraulicPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 53 thru 57)
52,905,946
73,683,795
59
PowerProductionExpensesHydraulicPower
TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
144,870,593
174,574,303
60
OtherPowerGenerationAbstract
D. Other Power Generation
61
OtherPowerGenerationOperationAbstract
Operation
62
OperationSupervisionAndEngineeringOtherPowerGeneration
(546) Operation Supervision and Engineering
593,029
186,426
63
Fuel
(547) Fuel
64
GenerationExpenses
(548) Generation Expenses
10,644,381
11,035,728
64.1
OperationOfEnergyStorageEquipment
(548.1) Operation of Energy Storage Equipment
65
MiscellaneousOtherPowerGenerationExpenses
(549) Miscellaneous Other Power Generation Expenses
939,016
3,161,565
66
RentsOtherPowerGeneration
(550) Rents
67
OtherPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 62 thru 67)
12,176,426
8,060,589
68
OtherPowerGenerationMaintenanceAbstract
Maintenance
69
MaintenanceSupervisionAndEngineeringOtherPowerGeneration
(551) Maintenance Supervision and Engineering
161,732
59,192
70
MaintenanceOfStructures
(552) Maintenance of Structures
2,848,377
2,735,312
71
MaintenanceOfGeneratingAndElectricPlant
(553) Maintenance of Generating and Electric Plant
7,166,782
5,487,309
71.1
MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration
(553.1) Maintenance of Energy Storage Equipment
72
MaintenanceOfMiscellaneousOtherPowerGenerationPlant
(554) Maintenance of Miscellaneous Other Power Generation Plant
5,692,471
2,924,933
73
OtherPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 69 thru 72)
15,869,362
11,206,746
74
PowerProductionExpensesOtherPower
TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)
28,045,788
19,267,335
75
OtherPowerSuplyExpensesAbstract
E. Other Power Supply Expenses
76
PurchasedPower
(555) Purchased Power
(a)
3,496,844,586
(g)
3,852,611,625
76.1
PowerPurchasedForStorageOperations
(555.1) Power Purchased for Storage Operations
77
SystemControlAndLoadDispatchingElectric
(556) System Control and Load Dispatching
78
OtherExpensesOtherPowerSupplyExpenses
(557) Other Expenses
314,924,584
277,460,451
79
OtherPowerSupplyExpense
TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)
3,811,769,170
4,130,072,076
80
PowerProductionExpenses
TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)
4,785,972,292
5,023,688,228
81
TransmissionExpensesAbstract
2. TRANSMISSION EXPENSES
82
TransmissionExpensesOperationAbstract
Operation
83
OperationSupervisionAndEngineeringElectricTransmissionExpenses
(560) Operation Supervision and Engineering
5,738,383
2,652,100
85
LoadDispatchReliability
(561.1) Load Dispatch-Reliability
86
LoadDispatchMonitorAndOperateTransmissionSystem
(561.2) Load Dispatch-Monitor and Operate Transmission System
32,099,953
28,980,843
87
LoadDispatchTransmissionServiceAndScheduling
(561.3) Load Dispatch-Transmission Service and Scheduling
88
SchedulingSystemControlAndDispatchServices
(561.4) Scheduling, System Control and Dispatch Services
23,000,855
26,125,073
89
ReliabilityPlanningAndStandardsDevelopment
(561.5) Reliability, Planning and Standards Development
90
TransmissionServiceStudies
(561.6) Transmission Service Studies
91
GenerationInterconnectionStudies
(561.7) Generation Interconnection Studies
92
ReliabilityPlanningAndStandardsDevelopmentServices
(561.8) Reliability, Planning and Standards Development Services
8,859,349
10,285,155
93
StationExpensesTransmissionExpense
(562) Station Expenses
7,988,173
6,400,713
93.1
OperationOfEnergyStorageEquipmentTransmissionExpense
(562.1) Operation of Energy Storage Equipment
94
OverheadLineExpense
(563) Overhead Lines Expenses
13,924,543
6,577,810
95
UndergroundLineExpensesTransmissionExpense
(564) Underground Lines Expenses
180,771
1,495,308
96
TransmissionOfElectricityByOthers
(565) Transmission of Electricity by Others
949,485
13,665,066
97
MiscellaneousTransmissionExpenses
(566) Miscellaneous Transmission Expenses
99,690,874
83,829,810
98
RentsTransmissionElectricExpense
(567) Rents
99
TransmissionOperationExpense
TOTAL Operation (Enter Total of Lines 83 thru 98)
192,432,386
180,011,878
100
TransmissionMaintenanceAbstract
Maintenance
101
MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses
(568) Maintenance Supervision and Engineering
1,184,331
832,264
102
MaintenanceOfStructuresTransmissionExpense
(569) Maintenance of Structures
703,947
645,279
103
MaintenanceOfComputerHardwareTransmission
(569.1) Maintenance of Computer Hardware
104
MaintenanceOfComputerSoftwareTransmission
(569.2) Maintenance of Computer Software
105
MaintenanceOfCommunicationEquipmentElectricTransmission
(569.3) Maintenance of Communication Equipment
106
MaintenanceOfMiscellaneousRegionalTransmissionPlant
(569.4) Maintenance of Miscellaneous Regional Transmission Plant
107
MaintenanceOfStationEquipmentTransmission
(570) Maintenance of Station Equipment
(b)
22,519,226
(h)
21,874,666
107.1
MaintenanceOfEnergyStorageEquipmentTransmission
(570.1) Maintenance of Energy Storage Equipment
108
MaintenanceOfOverheadLinesTransmission
(571) Maintenance of Overhead Lines
129,824,961
96,349,282
109
MaintenanceOfUndergroundLinesTransmission
(572) Maintenance of Underground Lines
1,699,411
192,100
110
MaintenanceOfMiscellaneousTransmissionPlant
(573) Maintenance of Miscellaneous Transmission Plant
725,484
1,070,803
111
TransmissionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 101 thru 110)
156,657,360
120,964,394
112
TransmissionExpenses
TOTAL Transmission Expenses (Total of Lines 99 and 111)
349,089,746
300,976,272
113
RegionalMarketExpensesAbstract
3. REGIONAL MARKET EXPENSES
114
RegionalMarketExpensesOperationAbstract
Operation
115
OperationSupervision
(575.1) Operation Supervision
116
DayAheadAndRealTimeMarketAdministration
(575.2) Day-Ahead and Real-Time Market Facilitation
117
TransmissionRightsMarketAdministration
(575.3) Transmission Rights Market Facilitation
118
CapacityMarketAdministration
(575.4) Capacity Market Facilitation
119
AncillaryServicesMarketAdministration
(575.5) Ancillary Services Market Facilitation
120
MarketMonitoringAndCompliance
(575.6) Market Monitoring and Compliance
121
MarketFacilitationMonitoringAndComplianceServices
(575.7) Market Facilitation, Monitoring and Compliance Services
13,832,809
14,650,908
122
RentsRegionalMarketExpenses
(575.8) Rents
123
RegionalMarketOperationExpense
Total Operation (Lines 115 thru 122)
13,832,809
14,650,908
124
RegionalMarketExpensesMaintenanceAbstract
Maintenance
125
MaintenanceOfStructuresAndImprovementsRegionalMarketExpenses
(576.1) Maintenance of Structures and Improvements
126
MaintenanceOfComputerHardware
(576.2) Maintenance of Computer Hardware
127
MaintenanceOfComputerSoftware
(576.3) Maintenance of Computer Software
128
MaintenanceOfCommunicationEquipmentRegionalMarketExpenses
(576.4) Maintenance of Communication Equipment
129
MaintenanceOfMiscellaneousMarketOperationPlant
(576.5) Maintenance of Miscellaneous Market Operation Plant
130
RegionalMarketMaintenanceExpense
Total Maintenance (Lines 125 thru 129)
131
RegionalMarketExpenses
TOTAL Regional Transmission and Market Operation Expenses (Enter Total of Lines 123 and 130)
13,832,809
14,650,908
132
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
133
DistributionExpensesOperationAbstract
Operation
134
OperationSupervisionAndEngineeringDistributionExpense
(580) Operation Supervision and Engineering
2,428,597
4,382,277
135
LoadDispatching
(581) Load Dispatching
136
StationExpensesDistribution
(582) Station Expenses
(c)
2,238,385
(i)
2,196,251
137
OverheadLineExpenses
(583) Overhead Line Expenses
30,749,818
20,503,087
138
UndergroundLineExpenses
(584) Underground Line Expenses
30,333,882
30,005,042
138.1
OperationOfEnergyStorageEquipmentDistribution
(584.1) Operation of Energy Storage Equipment
139
StreetLightingAndSignalSystemExpenses
(585) Street Lighting and Signal System Expenses
140
MeterExpenses
(586) Meter Expenses
1,646,498
1,691,253
141
CustomerInstallationsExpenses
(587) Customer Installations Expenses
15,512,197
14,004,409
142
MiscellaneousDistributionExpenses
(588) Miscellaneous Expenses
(d)
240,620,319
(j)
37,055,570
143
RentsDistributionExpense
(589) Rents
666,513
78,291
144
DistributionOperationExpensesElectric
TOTAL Operation (Enter Total of Lines 134 thru 143)
324,196,209
109,916,180
145
DistributionExpensesMaintenanceAbstract
Maintenance
146
MaintenanceSupervisionAndEngineering
(590) Maintenance Supervision and Engineering
1,165,788
4,493,803
147
MaintenanceOfStructuresDistributionExpense
(591) Maintenance of Structures
2,824,259
2,542,906
148
MaintenanceOfStationEquipment
(592) Maintenance of Station Equipment
(e)
26,624,095
(k)
26,724,342
148.1
MaintenanceOfEnergyStorageEquipment
(592.2) Maintenance of Energy Storage Equipment
149
MaintenanceOfOverheadLines
(593) Maintenance of Overhead Lines
751,642,765
528,832,572
150
MaintenanceOfUndergroundLines
(594) Maintenance of Underground Lines
38,420,026
41,892,183
151
MaintenanceOfLineTransformers
(595) Maintenance of Line Transformers
1,817,300
2,125,962
152
MaintenanceOfStreetLightingAndSignalSystems
(596) Maintenance of Street Lighting and Signal Systems
1,738,254
2,056,782
153
MaintenanceOfMeters
(597) Maintenance of Meters
7,806,252
7,058,358
154
MaintenanceOfMiscellaneousDistributionPlant
(598) Maintenance of Miscellaneous Distribution Plant
733,849
680,573
155
DistributionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 146 thru 154)
832,772,588
616,407,481
156
DistributionExpenses
TOTAL Distribution Expenses (Total of Lines 144 and 155)
1,156,968,797
726,323,661
157
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
158
CustomerAccountsExpensesOperationsAbstract
Operation
159
SupervisionCustomerAccountExpenses
(901) Supervision
6,941,089
12,819,397
160
MeterReadingExpenses
(902) Meter Reading Expenses
5,761,047
6,183,670
161
CustomerRecordsAndCollectionExpenses
(903) Customer Records and Collection Expenses
163,431,605
156,058,369
162
UncollectibleAccounts
(904) Uncollectible Accounts
26,821,384
42,122,468
163
MiscellaneousCustomerAccountsExpenses
(905) Miscellaneous Customer Accounts Expenses
675,994
1,226,397
164
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)
202,279,131
215,957,507
165
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
167
SupervisionCustomerServiceAndInformationExpenses
(907) Supervision
168
CustomerAssistanceExpenses
(908) Customer Assistance Expenses
442,540,037
512,432,586
169
InformationalAndInstructionalAdvertisingExpenses
(909) Informational and Instructional Expenses
170
MiscellaneousCustomerServiceAndInformationalExpenses
(910) Miscellaneous Customer Service and Informational Expenses
404,461
471,252
171
CustomerServiceAndInformationExpenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
442,944,498
512,903,838
172
SalesExpenseAbstract
7. SALES EXPENSES
173
SalesExpenseOperationAbstract
Operation
174
SupervisionSalesExpense
(911) Supervision
175
DemonstratingAndSellingExpenses
(912) Demonstrating and Selling Expenses
961,730
1,194,885
176
AdvertisingExpenses
(913) Advertising Expenses
177
MiscellaneousSalesExpenses
(916) Miscellaneous Sales Expenses
178
SalesExpenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
961,730
1,194,885
179
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
180
AdministrativeAndGeneralExpensesOperationAbstract
Operation
181
AdministrativeAndGeneralSalaries
(920) Administrative and General Salaries
216,675,790
304,370,923
182
OfficeSuppliesAndExpenses
(921) Office Supplies and Expenses
10,731,390
55,729,129
183
AdministrativeExpensesTransferredCredit
(Less) (922) Administrative Expenses Transferred-Credit
36,224,106
50,102,503
184
OutsideServicesEmployed
(923) Outside Services Employed
276,922,321
162,252,920
185
PropertyInsurance
(924) Property Insurance
10,118,251
14,161,414
186
InjuriesAndDamages
(925) Injuries and Damages
12,202,690,726
190,423,721
187
EmployeePensionsAndBenefits
(926) Employee Pensions and Benefits
(f)
273,560,929
384,675,276
188
FranchiseRequirements
(927) Franchise Requirements
89,640,572
102,108,129
189
RegulatoryCommissionExpenses
(928) Regulatory Commission Expenses
190
DuplicateChargesCredit
(929) (Less) Duplicate Charges-Cr.
191
GeneralAdvertisingExpenses
(930.1) General Advertising Expenses
121,950
192
MiscellaneousGeneralExpenses
(930.2) Miscellaneous General Expenses
11,017,410
6,306,443
193
RentsAdministrativeAndGeneralExpense
(931) Rents
194
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Enter Total of Lines 181 thru 193)
13,033,670,503
1,170,047,402
195
AdministrativeAndGeneralExpensesMaintenanceAbstract
Maintenance
196
MaintenanceOfGeneralPlant
(935) Maintenance of General Plant
4,725,363
8,482,612
197
AdministrativeAndGeneralExpenses
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
13,038,395,866
1,178,530,014
198
OperationsAndMaintenanceExpensesElectric
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)
19,990,444,869
7,974,225,313


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PurchasedPower

Of the year end balance, ($220,207) relates to energy storage operation per FERC Order 784.

(b) Concept: MaintenanceOfStationEquipmentTransmission

Of the year end balance, $0 relates to energy storage operation per FERC Order 784.

(c) Concept: StationExpensesDistribution

Of the quarter end balance, $0 relate to energy storage operation per FERC Order 784.

(d) Concept: MiscellaneousDistributionExpenses

Of the quarter end balance, $0 relate to energy storage operation per FERC Order 784.

(e) Concept: MaintenanceOfStationEquipment

Of the quarter end balance, $185,192 relate to energy storage operation per FERC Order 784.

(f) Concept: EmployeePensionsAndBenefits

Of the quarter end balance, $0 relate to energy storage operation per FERC Order 784.

(g) Concept: PurchasedPower

Of the year end balance, $204,601 relates to energy storage operation per FERC Order 784.

(h) Concept: MaintenanceOfStationEquipmentTransmission

Of the year end balance, $0 relates to energy storage operation per FERC Order 784.

(i) Concept: StationExpensesDistribution

Of the quarter end balance, $0 relate to energy storage operation per FERC Order 784.

(j) Concept: MiscellaneousDistributionExpenses

Of the quarter end balance, $693 relate to energy storage operation per FERC Order 784.

(k) Concept: MaintenanceOfStationEquipment

Of the quarter end balance, $196,979 relate to energy storage operation per FERC Order 784.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
PURCHASED POWER (Account 555)
  1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
  2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
  3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:

    RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers.

    LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract.

    IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years.

    SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less.

    LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit.

    IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years.

    EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges.

    OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment.

    AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment.

  4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided.
  5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
  6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (i) and (j) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
  7. Report demand charges in column (k), energy charges in column (l), and the total of any other types of charges, including out-of-period adjustments, in column (m). Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (n) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (m) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote.
  8. The data in column (g) through (n) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (i) must be reported as Exchange Received on Page 401, line 12. The total amount in column (j) must be reported as Exchange Delivered on Page 401, line 13.
  9. Footnote entries as required and provide explanations following all required data.
Actual Demand (MW) POWER EXCHANGES COST/SETTLEMENT OF POWER
Line No.
NameOfCompanyOrPublicAuthorityProvidingPurchasedPower
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
RateScheduleTariffNumber
Ferc Rate Schedule or Tariff Number
(c)
AverageMonthlyBillingDemand
Average Monthly Billing Demand (MW)
(d)
AverageMonthlyNonCoincidentPeakDemand
Average Monthly NCP Demand
(e)
AverageMonthlyCoincidentPeakDemand
Average Monthly CP Demand
(f)
MegawattHoursPurchasedOtherThanStorage
MegaWatt Hours Purchased (Excluding for Energy Storage)
(g)
MegawattHoursPurchasedForEnergyStorage
MegaWatt Hours Purchased for Energy Storage
(h)
EnergyReceivedThroughPowerExchanges
MegaWatt Hours Received
(i)
EnergyDeliveredThroughPowerExchanges
MegaWatt Hours Delivered
(j)
DemandChargesOfPurchasedPower
Demand Charges ($)
(k)
EnergyChargesOfPurchasedPower
Energy Charges ($)
(l)
OtherChargesOfPurchasedPower
Other Charges ($)
(m)
SettlementOfPower
Total (k+l+m) of Settlement ($)
(n)
1
QUALIFYING FACILITIES (QF's)
0.00000
0.00000
2
RENEWABLES:
0.00000
0.00000
3
BIOGAS-CITY OF WATSONVILLE
0.00000
0.05920
27
82
1,337
1,419
4
MONTEREY REGIONAL WATER
0.00000
0.21390
487
2,872
16,633
19,505
5
WASTE MANAGEMENT RENEWABLE
0.00000
4.93400
2,580
5,758
94,512
100,270
6
BIOMASS-WHEELABRATOR SHASTA
49.68000
34.28670
1,192
21,870
27,851
5,981
7
HYDRO-CHARCOAL RAVINE
0.00000
0.00050
3
14
114
128
8
EIF HAYPRESS LLC LWR
0.00000
1.54350
6,622
124,678
237,373
362,051
9
EIF HAYPRESS LLC MDL
0.00000
2.07830
9,363
167,766
334,978
502,744
10
EL DORADO MONTGOMERY CREEK
0.00000
1.49590
5,233
64,650
706,165
770,815
11
FIVE BEARS HYDROELECTRIC
0.00000
0.21400
282
1,868
10,020
11,888
12
GANSNER HYDRO
0.00000
0.04580
108
553
3,834
4,387
13
HAT CREEK HEREFORD RANCH
0.00000
0.01480
13,108
356,938
555,063
912,001
14
HYDRO PARTNERS CLOVER CREEK
0.00000
0.83990
1,317
5,373
41,539
46,912
15
HYDRO SIERRA DEADWOOD CREEK
0.00000
0.77700
1,906
23,431
62,643
86,074
16
HYPOWER INC.
0.00000
5.16950
28,312
295,160
914,232
1,209,392
17
INDIAN VALLEY HYDRO
0.00000
1.19990
2,385
20,215
81,525
101,740
18
JAMES B. PETER
0.00000
0.00000
26
103
804
907
19
JAMES CRANE HYDRO
0.00000
0.00050
4
10
150
160
20
KINGS RIVER HYDRO
0.00000
0.34220
1,406
38,356
55,517
93,873
21
LOFTON RANCH
0.00000
0.12570
964
6,059
33,463
39,522
22
MALACHA HYDRO L.P.
0.00000
25.40150
47,753
1,538,760
1,867,768
3,406,528
23
NELSON CREEK POWER
0.00000
0.28000
974
12,540
35,810
48,350
24
OLCESE WATER DISTRICT
0.00000
4.37530
23,754
198,636
903,579
1,102,215
25
OLSEN POWER PARTNERS
0.00000
1.75250
6,098
60,387
204,655
265,042
26
ORANGE COVE IRRIGATION DISTRICT
0.00000
0.46400
3,853
82,535
143,847
226,382
27
SANTA CLARA VALLEY WATER DIST.
0.00000
0.35320
2,089
77,630
77,630
28
SCHAADS HYDRO
0.00000
0.11320
365
1,954
12,605
14,559
29
SNOW MOUNTAIN BURNEY CREEK
0.00000
1.24890
3,386
36,361
124,070
160,431
30
SNOW MOUNTAIN COVE
0.00000
2.51720
9,196
143,057
698,793
841,850
31
SNOW MT. PONDEROSA BAILEY CREEK
0.00000
0.54500
1,779
28,766
43,574
72,340
32
SUTTER'S MILL SHAMROCK UTILITIES
0.00000
0.00000
61
139
2,273
2,412
33
SWISS AMERICA
0.00000
0.03110
212
1,823
7,631
9,454
34
TOM BENNINGHOVEN
0.00000
0.00740
49
225
1,794
2,019
35
SOLAR-VILLA SORRISO SOLAR
0.00000
0.00080
7
25
246
271
36
WIND-DONALD R. CHENOWETH
0.00000
0.00070
6
21
223
244
37
EDF RENEWABLE WINDFARM V, INC (70 MW -
0.00000
0.00000
1,144
1,361
41,924
43,285
38
EDF RENEWABLE INC 70 MW C
0.00000
1.67040
3,541
92,854
133,606
226,460
39
EDF RENEWABLE INC 10 MW
0.00000
0.00000
782
1,523
26,570
28,093
40
INTERNATIONAL TURBINE RESEARCH
0.00000
6.66540
10,720
257,011
392,665
649,676
41
THERMAL:
0.00000
0.00000
42
COGEN-1080 CHESTNUT CORP.
0.00000
0.00170
15
58
564
622
43
AIRPORT CLUB
0.00000
0.00210
17
50
626
676
44
ARDEN WOOD BENEVOLENT ASSOC.
0.00000
0.00010
1
4
36
40
45
BERKELEY COGENERATION
22.47000
2.40700
8,799
60,237
147,916
208,153
46
CALPINE KING CITY COGEN
111.00000
121.05810
393,881
24,936,469
14,695,346
39,631,815
47
CHEVRON RICHMOND REFINERY
0.00000
2.78330
1,156
2,639
55,392
58,031
48
COUNTY OF SANTA CRUZ ( WATER ST. JAIL)
0.00000
0.00000
7
7
49
CROCKETT COGEN
240.00000
239.77570
1,393,652
52,220,644
56,180,444
108,401,088
50
ECO SERVICES OPERATIONS LLC
0.00000
0.36770
357
1,029
13,330
14,359
51
FRESNO COGENERATION PARTNERS, LP
33.00000
21.42570
1,683
7,305,734
199,384
7,505,118
52
FRITO-LAY COGEN
0.00000
0.52310
632
3,859
24,677
28,536
53
GREATER VALLEJO RECREATION DIST.
0.00000
0.00380
36
109
1,269
1,378
54
GREENLEAF UNIT 1
49.20000
48.04160
73,004
9,042,139
3,506,775
12,548,914
55
GREENLEAF UNIT 2
49.20000
47.43360
224,224
10,015,038
8,021,211
18,036,249
56
HAYWARD AREA RECREATION AND PARK
0.00000
0.04570
407
1,240
15,020
16,260
57
NIHONMACHI TERRACE
0.00000
0.00130
13
40
487
527
58
ORINDA SENIOR VILLAGE
0.00000
0.00140
14
40
546
586
59
PE KES KINGSBURG LLC
34.50000
13.49420
4,443
8,851,300
311,365
9,162,665
60
PHILLIPS 66
0.00000
8.16550
22,202
127,965
870,675
998,640
61
SATELLITE SENIOR HOMES
0.00000
0.00470
2
57
57
62
SRI INTERNATIONAL
0.00000
1.79630
7,129
16,348
278,781
295,129
63
YUBA CITY COGEN
46.00000
42.79940
10,655
10,444,146
484,681
10,928,827
64
EOR-AERA ENERGY LLC COALINGA
0.00000
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27,182
230,290
257,472
65
AERA ENERGY SOUTH BELRIDGE
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1.33030
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22,710
169,664
192,374
66
BERRY PETROLEUM CO - TANNEHILL
0.00000
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90,144
675,895
3,464,323
4,140,218
67
CHEVRON USA TAFT/CADET
0.00000
2.06630
4,239
36,949
166,985
203,934
68
CHEVRON USA CYMRIC
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21,550
135,086
825,170
960,256
69
CHEVRON USA COALINGA
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11,252
112,038
420,854
532,892
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CHEVRON USA INC EASTRIDGE
0.00000
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14,725
78,562
584,295
662,857
71
CHEVRON USA INC SE KERN RIVER
0.00000
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4,078
34,728
155,547
190,275
72
CHEVRON MCKITTRICK FHP
0.00000
3.49840
19,701
1,260,401
1,260,401
73
COALINGA COGENERATION COMPANY
37.70000
0.00000
150,000
150,000
74
FREEPORT MCMORAN DOME
0.00000
1.83950
7,808
40,555
279,581
320,136
75
SENTINEL PEAK RESOURCES
0.00000
1.83950
82
2,957
42,290
39,333
76
WESTERN POWER & STEAM INC
17.75000
18.28810
134,424
1,548,892
5,100,979
6,649,871
77
BILATERALS
0.00000
0.00000
78
2041 ALVARES PRISTINE SUN
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0.00000
552
78,789
78,789
79
2056 JARDINE PRISTINE SUN
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0.00000
2,240
313,368
313,368
80
2059 SCHERZ
0.00000
0.00000
1,014
143,118
143,118
81
2065 ROGERS PRISTINE SUN
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0.00000
533
73,308
73,308
82
2081 TERZIAN
0.00000
0.00000
1,459
208,583
208,583
83
2094 BUZZELLE PRISTINE SUN
0.00000
0.00000
590
79,616
79,616
84
2096 COTTON PRISTINE SUN
0.00000
0.00000
1,889
283,192
283,192
85
2097 HELTON PRISTINE SUN
0.00000
0.00000
241
29,133
29,133
86
2102 CHRISTENSEN PRISTINE SUN
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2,183
311,460
311,460
87
2103 HILL PRISTINE SUN
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0.00000
590
86,747
86,747
88
2105 HART (Oroville Solar)
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81,335
81,335
89
2113 FITZJARRELL PRISTINE SUN
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601
81,154
81,154
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2125 JARVIS PRISTINE SUN
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542
79,124
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91
2127 HARRIS PRISTINE SUN
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389,800
389,800
92
2154 FOOTE (Oroville Solar)
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64,740
64,740
93
2158 STROING PRISTINE SUN
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166,623
166,623
94
2179 SMOTHERMAN
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82,424
82,424
95
2184 GRUBER (ENERPARC)
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344,700
344,700
96
2192 RAMIREZ (Oroville Solar)
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0.00000
1,028
136,445
136,445
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2018 REC Sales Oct-Dec Accrual
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0.00000
1,001,962
16,795,368
16,795,368
98
3 PHASES 2017 REC SALE
0.00000
0.00000
13,721
226,397
226,397
99
3 PHASES RENEWABLES INC
0.00000
0.00000
970,300
970,300
100
ABEC #2 LLC
0.00000
0.00000
2,629
524,367
524,367
101
ABEC #3 LLC
0.00000
0.00000
14,907
2,733,671
2,733,671
102
ABEC #4 LLC
0.00000
0.00000
2,574
523,641
523,641
103
ABEC BIDART OLD RIVER
0.00000
0.00000
11,883
1,727,324
1,727,324
104
ABEC BIDART-STOCKDALE LLC
0.00000
0.00000
849
151,259
404
150,855
105
AGUA CALIENTE SOLAR
0.00000
0.00000
727,004
127,047,414
127,047,414
106
ALAMO SOLAR
0.00000
0.00000
52,717
4,549,112
4,549,112
107
ALGONQUIN SANGER POWER LLC
0.00000
0.00000
8,168,240
8,168,240
108
ALGONQUIN SKIC 20 SOLAR, LLC
0.00000
0.00000
48,129
4,275,544
4,275,544
109
ALPAUGH 50, LLC
0.00000
0.00000
120,849
20,121,508
20,121,508
110
ALPAUGH NORTH, LLC
0.00000
0.00000
48,144
7,658,962
7,658,962
111
Anahau Energy, LLC EEI Master
0.00000
0.00000
5,291,500
5,291,500
112
ANGELS POWERHOUSE
0.00000
0.00000
5,831
641,616
641,616
113
APEX 646-460
0.00000
0.00000
1,804
234,362
234,362
114
ARBUCKLE MOUNTAIN HYDRO
0.00000
0.00000
30
2,392
2,392
115
ARLINGTON WIND POWER PROJECT
0.00000
0.00000
223,688
22,757,238
22,757,238
116
ASPIRATION SOLAR G
0.00000
0.00000
22,418
1,484,040
1,484,040
117
ATWELL ISLAND
0.00000
0.00000
39,526
6,563,130
6,563,130
118
AV SOLAR RANCH ONE
0.00000
0.00000
603,741
92,957,348
3,000,000
89,957,348
119
AVENAL SOLAR PROJECT A
0.00000
0.00000
17,391
970,391
970,391
120
AVENAL SOLAR PROJECT B
0.00000
0.00000
16,977
951,949
951,949
121
BADGER CREEK LIMITED
0.00000
0.00000
8,098
3,903,454
155,570
4,059,024
122
BAKER CREEK HYDROELECTRIC PROJECT
0.00000
0.00000
3,250
331,687
331,687
123
BAKERSFIELD 111 LLC
0.00000
0.00000
2,963
388,561
388,561
124
BAKERSFIELD INDUSTRIAL 1
0.00000
0.00000
2,201
158,494
158,494
125
BAKERSFIELD PV 1
0.00000
0.00000
10,763
440,110
440,110
126
BAYSHORE SOLAR A
0.00000
0.00000
59,488
3,317,811
3,317,811
127
BAYSHORE SOLAR B
0.00000
0.00000
60,813
3,364,350
3,364,350
128
BAYSHORE SOLAR C
0.00000
0.00000
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3,279,556
3,279,556
129
BEAR CREEK SOLAR LLC
0.00000
0.00000
3,316
495,458
495,458
130
BEAR MOUNTAIN LIMITED
0.00000
0.00000
38,833
3,903,454
573,310
4,476,764
131
BGC BROKERAGE
0.00000
0.00000
16,170
16,170
132
BIG CREEK WATER WORKS
0.00000
0.00000
6,338
565,095
565,095
133
BLACKSPRING RIDGE 1A
0.00000
0.00000
15,019,220
15,019,220
134
BLACKSPRING RIDGE 1B
0.00000
0.00000
16,224,527
16,224,527
135
BLAKE'S LANDING FARMS INC
0.00000
0.00000
172
13,725
13,725
136
BONNEVILLE POWER ADMINSTRATION (KLONDI
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0.00000
554,313
554,313
137
BP Energy Company
0.00000
0.00000
107,913
253,600
9,316,573
9,062,973
138
BPA TSA
0.00000
0.00000
5,161
5,161
139
BROWNS VALLEY IRRIGATION DIST
0.00000
0.00000
3,251
258,571
258,571
140
BUCKEYE HYDROELECTRIC PROJECT
0.00000
0.00000
1,486
141,061
141,061
141
BURNEY FOREST PRODUCTS
0.00000
0.00000
9,300
9,300
142
CALAVERAS PUBLIC UTILI. DIST. 1
0.00000
0.00000
483
47,119
47,119
143
CALAVERAS PUBLIC UTILI. DIST. 2
0.00000
0.00000
291
28,176
28,176
144
CALAVERAS PUBLIC UTILI. DIST. 3
0.00000
0.00000
126
12,235
12,235
145
CALPINE ENERGY - AGNEWS, INC
0.00000
0.00000
16,289
5,895,251
308,486
6,203,737
146
CALPINE ENERGY EEI
0.00000
0.00000
1,023,500
1,023,500
147
CALPINE GEYSERS (200/425 MW)
0.00000
0.00000
180,250
16,462,518
16,462,518
148
CALPINE GEYSERS RETAINED ASSET AGREEME
0.00000
0.00000
18,344
18,344
149
CALPINE LOS ESTEROS UPGRADE
0.00000
0.00000
365,125
67,348,231
7,760,890
75,109,121
150
CALPINE PEAKERS
0.00000
0.00000
89,971
31,239,530
3,670,844
34,910,374
151
CALPINE RUSSELL CITY
0.00000
0.00000
1,342,740
144,530,861
20,638,030
165,168,891
152
CALRENEW CLEANTECH
0.00000
0.00000
9,899
2,229,862
2,229,862
153
CAMS DOUBLE C LIMITED
0.00000
0.00000
26,511
5,096,356
549,529
17,252
5,628,633
154
CAMS HIGH SIERRA LIMITED
0.00000
0.00000
28,158
5,073,452
598,394
19,528
5,652,318
155
CAMS KERN FRONT LIMITED
0.00000
0.00000
18,988
5,094,374
692,762
14,072
5,773,064
156
CASTELANELLI BROS BIOGAS
0.00000
0.00000
906
86,857
86,857
157
CASTOR SOLAR PROJECT
0.00000
0.00000
2,619
336,201
336,201
158
CE of Montana
0.00000
0.00000
348,250
348,250
159
CED CORCORAN SOLAR 3 LLC
0.00000
0.00000
52,178
2,554,984
2,554,984
160
CED WHITE RIVER SOLAR, LLC
0.00000
0.00000
1,332
177,441
177,441
161
CEDAR FLAT (Shamrock Utilities)
0.00000
0.00000
993
100,890
100,890
162
CHALK CLIFF LIMITED
0.00000
0.00000
16,765
3,885,559
305,254
4,190,813
163
CID SOLAR LLC RAM 2
0.00000
0.00000
52,849
5,657,262
5,657,262
164
CITY OF SAN JOSE
165
CITY OF SJ"
0.00000
0.00000
240,540
240,540
166
CITY OF SANTA CLARA SVP MUNI
0.00000
0.00000
699,750
699,750
167
CITY OF VERNON
0.00000
0.00000
126,500
126,500
168
CLEAN PWR ALLIANCE
0.00000
0.00000
338,919
338,919
169
CLEANPOWERSF
0.00000
0.00000
5,275,400
5,275,400
170
CLOVER FLAT LFG
0.00000
0.00000
5,199
519,391
2,787
516,604
171
CLOVER LEAF (Shamrock Utilities)
0.00000
0.00000
716
75,797
75,797
172
CLOVERDALE SOLAR 1, LLC
0.00000
0.00000
2,601
383,147
383,147
173
COLUMBIA SOLAR ENERGY LLC
0.00000
0.00000
38,127
3,780,655
200,000
3,580,655
174
COPPER MOUNTAIN 10
0.00000
0.00000
20,587
3,349,717
3,349,717
175
COPPER MOUNTAIN SOLAR 2 (SEMPRA)
0.00000
0.00000
373,073
48,359,434
48,359,434
176
COPPER MOUNTAIN SOLAR 48
0.00000
0.00000
99,882
16,243,373
16,243,373
177
CORAM BRODIE WIND
0.00000
0.00000
275,443
31,679,368
31,679,368
178
CORCORAN SOLAR
0.00000
0.00000
50,114
7,500,814
7,500,814
179
DELANO PV 1 LLC
0.00000
0.00000
2,186
158,367
158,367
180
DESERT CENTER SOLAR FARM
0.00000
0.00000
737,230
116,803,579
116,803,579
181
DIGGER CREEK HYDRO
0.00000
0.00000
3,033
307,728
307,728
182
DIRECT ENERGY BUSINESS MARKETING
0.00000
0.00000
2,219,750
2,219,750
183
DTE STOCKTON
0.00000
0.00000
372,295
48,523,322
48,523,322
184
DTE SUNSHINE GAS LANDFILL
0.00000
0.00000
149,138
17,988,201
17,988,201
185
EAST BAY COMMUNITY ENERGY
0.00000
0.00000
378,778
20,935,413
1,738,591
22,674,004
186
EAST BAY COMMUNITY ENERGY AUTHORITY -
0.00000
0.00000
156,222
717,059
717,059
187
ECOS ENERGY LLC KETTLEMAN SOLAR
0.00000
0.00000
2,223
321,462
321,462
188
EDF TRADING - BU
0.00000
0.00000
364,500
364,500
189
EDF TRADING 2017 REC SALE
0.00000
0.00000
283,357
283,357
190
EDF Trading EEI
0.00000
0.00000
6,142,972
6,142,972
191
EIF PANOCHE (FIREBAUGH)
0.00000
0.00000
636,160
55,634,546
5,567,591
61,202,137
192
EL DORADO IRRIGATION DISTRICT
0.00000
0.00000
59,377
5,878,544
5,878,544
193
ENERPARC CA1 LLC
0.00000
0.00000
3,594
530,100
530,100
194
EQUUS ENERGY BROKER
0.00000
0.00000
5,040
5,040
195
ETIWANDA POWER PLANT
0.00000
0.00000
50,133
2,199,661
2,199,661
196
EURUS (AVENAL PARK, LLC)
0.00000
0.00000
10,443
2,637,099
2,637,099
197
EURUS (SAND DRAG, LLC)
0.00000
0.00000
35,044
8,767,139
8,767,139
198
EURUS (SUN CITY PROJECT, LLC)
0.00000
0.00000
36,799
9,206,217
9,206,217
199
Exelon
0.00000
0.00000
60,000
2,347,484
2,347,484
200
EXELON GENERATION COMPANY
0.00000
0.00000
250,000
4,000,000
4,000,000
201
EXELON GENERATION WSPP
0.00000
0.00000
125,876
7,857,450
6,122,882
1,734,568
202
FALL RIVER MILLS A ACHOMAWI
0.00000
0.00000
3,458
509,515
509,515
203
FALL RIVER MILLS B AHJUMAWI
0.00000
0.00000
3,437
507,643
507,643
204
FPL Energy Power Marketing Inc.
0.00000
0.00000
250,250
250,250
205
FRESH AIR ENERGY IV SONORA 1
0.00000
0.00000
3,596
504,882
504,882
206
FRESNO SOLAR SOUTH
0.00000
0.00000
3,031
394,508
394,508
207
FRESNO SOLAR WEST
0.00000
0.00000
3,221
416,989
416,989
208
GAS TRANSPORT ASSOC WITH PANOCHE ENERG
0.00000
0.00000
1,484,416
1,484,416
209
GENESIS SOLAR ENERGY PROJECT
0.00000
0.00000
621,742
133,270,780
2,360,000
130,910,780
210
GEYSERS 50/250/425 MW
0.00000
0.00000
2,003,824
10,862,500
154,438,678
165,301,178
211
GLOBAL AMPERSAND, CHOWCHILLA
0.00000
0.00000
69,781
7,830,172
7,830,172
212
GLOBAL AMPERSAND, EL NIDO
0.00000
0.00000
67,970
7,527,476
7,527,476
213
GOOSE VALLEY FARMING, LLC
0.00000
0.00000
281
25,477
25,477
214
GREEN LIGHT ENERGY SIRUIS SOLAR
0.00000
0.00000
1,448
185,492
185,492
215
GREEN LIGHT MADERA 1
0.00000
0.00000
2,863
161,114
161,114
216
GWF HANFORD
0.00000
0.00000
15,604
8,369,979
216,350
8,586,329
217
GWF HENRIETTA
0.00000
0.00000
32,573
8,308,350
565,484
8,873,834
218
GWF TRACY REPOWERING PPA
0.00000
0.00000
911,735
66,895,676
10,746,212
77,641,888
219
HALKIRK I WIND PROJECT
0.00000
0.00000
16,851,744
842,587
17,694,331
220
HATCHET RIDGE WIND LLC
0.00000
0.00000
242,474
25,781,312
25,781,312
221
HENRIETTA SOLAR
0.00000
0.00000
252,661
26,281,045
26,281,045
222
HIGH PLAINS RANCH II
0.00000
0.00000
553,146
72,823,849
7,650,000
65,173,849
223
HIGH PLAINS RANCH III
0.00000
0.00000
111,253
15,587,362
1,350,000
14,237,362
224
HOLLISTER SOLAR ECOS ENERGY
0.00000
0.00000
4,076
545,335
545,335
225
IBERDROLA KLONDIKE (AKA PPM KLONDIKE)
0.00000
0.00000
202,019
11,818,140
11,818,140
226
IBERDROLA RENEWABLES (AKA PPM ENERGY)
0.00000
0.00000
19,953
5,732,398
5,732,398
227
ICE Broker Agreement
0.00000
0.00000
107,450
107,450
228
IVANPAH UNIT 1
0.00000
0.00000
239,049
39,116,577
1,000,000
38,116,577
229
IVANPAH UNIT 3
0.00000
0.00000
277,399
45,559,054
1,100,000
44,459,054
230
JACKSON VALLEY IRRIGATION DIST
0.00000
0.00000
801
72,409
72,409
231
KANSAS
0.00000
0.00000
52,264
5,395,223
5,395,223
232
KEKAWAKA CREEK HYDRO RAM 4
0.00000
0.00000
7,513
500,535
500,535
233
KENT SOUTH - PV 2
0.00000
0.00000
52,614
4,553,039
4,553,039
234
KERN RIVER COGEN (KRCC)
0.00000
0.00000
732,322
22,109,935
26,651,081
48,761,016
235
KINGSBURG 1 TULARE PV II LLC
0.00000
0.00000
2,831
398,845
398,845
236
KINGSBURG 2 TULARE PV II LLC
0.00000
0.00000
2,924
407,285
407,285
237
KINGSBURG 3 TULARE PV II LLC
0.00000
0.00000
1,419
198,547
198,547
238
KLONDIKE WIND IIIA POWER
0.00000
0.00000
228,990
17,943,046
17,943,046
239
LA JOYA DEL SOL 1
0.00000
0.00000
3,098
398,205
398,205
240
LASSEN STATION
0.00000
0.00000
3,406
357,114
357,114
241
LEMOORE PV 1, LLC
0.00000
0.00000
3,552
480,912
480,912
242
LIVE OAK LIMITED
0.00000
0.00000
25,146
3,891,874
465,701
4,357,575
243
LOST CREEK 1
0.00000
0.00000
5,523
563,961
563,961
244
LOST CREEK 2
0.00000
0.00000
2,537
257,917
257,917
245
Macquarie Futures
0.00000
0.00000
862,471
862,471
246
MACQUARIE FUTURES USA - EGS-FCM
0.00000
0.00000
830,992
830,992
247
MADERA CHOWCHILLA - SITE 1923
0.00000
0.00000
1,474
129,456
129,456
248
MADERA CHOWCHILLA SITE 1174
0.00000
0.00000
1,379
122,358
122,358
249
MADERA CHOWCHILLA SITE 1302
0.00000
0.00000
825
73,792
73,792
250
MADERA CHOWCHILLA SITE 980
0.00000
0.00000
3,915
347,870
347,870
251
MAMMOTH G1 (ORMAT) - RAM 2
0.00000
0.00000
56,816
4,871,902
4,871,902
252
MAMMOTH G3 (M3 ORMAT) - RAM 1
0.00000
0.00000
85,693
7,774,977
7,774,977
253
MANTECA LAND 1
0.00000
0.00000
1,888
146,515
146,515
254
MARIN CLEAN ENERGY - BU
0.00000
0.00000
220,000
220,000
255
MARIN CLEAN ENERGY EEI
0.00000
0.00000
9,966,458
9,966,458
256
MARIPOSA ENERGY, LLC
0.00000
0.00000
112,215
29,859,433
2,029,011
31,888,444
257
MARSH LANDING
0.00000
0.00000
203,650
118,582,704
5,463,398
124,046,102
258
MATTHEWS DAM HYDRO
0.00000
0.00000
4,398
468,161
468,161
259
MBCPA - BU
0.00000
0.00000
84,990
84,990
260
MCFADDEN HYDRO FACILITY
0.00000
0.00000
3,223
303,561
303,561
261
MCKITTRICK LIMITED
0.00000
0.00000
30,290
3,867,158
324,473
4,191,631
262
MERCED 1
0.00000
0.00000
5,332
210,100
210,100
263
MERCED IRRIGATION DISTRICT
0.00000
0.00000
135,965
135,965
264
MERCED SOLAR ECOS ENERGY
0.00000
0.00000
2,678
345,193
345,193
265
MESQUITE SOLAR
0.00000
0.00000
30,332
3,962,762
3,962,762
266
MIDWAY SUNSET COGENERATION COMPANY
0.00000
0.00000
838,496
14,312,723
4,858,988
9,453,735
267
MILL SULPHUR CREEK PROJECT
0.00000
0.00000
1,142
118,605
118,605
268
MISSION SOLAR ECOS ENERGY
0.00000
0.00000
2,708
348,718
348,718
269
MOJAVE SOLAR
0.00000
0.00000
602,251
120,925,541
6,227,437
114,698,104
270
MONTEREY BAY COMMUNITY POWER
0.00000
0.00000
11,484,910
11,484,910
271
MORELOS SOLAR LLC - RAM 3
0.00000
0.00000
38,517
3,500,901
3,500,901
272
Morgan Stanley
0.00000
0.00000
20,000
879,072
879,072
273
MORGAN STANLEY CAPITAL GROUP EEI
0.00000
0.00000
103,029
183,750
3,039,010
3,222,760
274
MT. POSO (RED HAWK)
0.00000
0.00000
242,938
32,289,860
350,000
31,939,860
275
NCPA
0.00000
0.00000
1,481,500
1,481,500
276
NEXTERA DIABLO WINDS
0.00000
0.00000
61,538
3,435,835
3,435,835
277
NEXTERA MONTEZUMA WIND
0.00000
0.00000
95,498
9,645,261
320,000
9,325,261
278
NEXTERA MONTEZUMA WIND II
0.00000
0.00000
214,040
21,837,602
21,837,602
279
NICKEL 1 NLH1 SOLAR
0.00000
0.00000
2,830
377,148
377,148
280
NID CHICAGO PARK
0.00000
0.00000
119,406
10,784,248
10,784,248
281
NID NORTH COMBIE FIT
0.00000
0.00000
1,494
160,739
160,739
282
NID SCOTTS FLAT
0.00000
0.00000
4,321
383,752
383,752
283
NID SOUTH COMBIE FIT
0.00000
0.00000
5,576
520,804
520,804
284
NID-DUTCH FLATS, ROLLINS, BOWMAN
0.00000
0.00000
136,247
12,333,536
12,333,536
285
NORTH SKY RIVER ENERGY CENTER
0.00000
0.00000
441,975
38,407,665
38,407,665
286
NORTH STAR SOLAR
0.00000
0.00000
154,435
19,914,450
19,914,450
287
NRG ALPINE SOLAR
0.00000
0.00000
162,698
23,738,562
23,738,562
288
NRG POWER MARKETING LLC
0.00000
0.00000
35,468
35,468
289
NRG SOLAR KANSAS SOUTH
0.00000
0.00000
48,988
4,657,853
4,657,853
290
OAKLEY EXECUTIVE LLC
0.00000
0.00000
2,219
317,895
317,895
291
OLD RIVER ONE LLC - RAM 3
0.00000
0.00000
50,330
4,251,478
4,251,478
292
ORION SOLAR I LLC
0.00000
0.00000
29,115
3,698,712
3,698,712
293
OROVILLE COGEN TOLLING
0.00000
0.00000
206
1,110,435
1,900
1,108,535
294
ORTIGALITA POWER COMPANY LLC
0.00000
0.00000
3
3
295
PACIFICORP TSA
0.00000
0.00000
7,891
7,891
296
PCWA LINCOLN HYDRO
0.00000
0.00000
1,329
144,031
144,031
297
PEACOCK SOLAR PROJ - GREEN LIGHT
0.00000
0.00000
1,817
243,159
243,159
298
PENINSULA 2017 REC SALE
0.00000
0.00000
299
PENINSULA CLEAN ENERGY
0.00000
0.00000
541,750
541,750
300
PENINSULA CLEAN ENERGY EEI
0.00000
0.00000
4,390,484
4,390,484
301
PILOT POWER GROUP INC
0.00000
0.00000
837,750
837,750
302
PIONEER COMM ENERGY
0.00000
0.00000
1,898,700
1,898,700
303
PLACER COUNTY WATER AGENCY
0.00000
0.00000
375,067
592,893
592,893
304
PORTAL RIDGE SOLAR C PROJECT
0.00000
0.00000
30,107
1,942,471
1,942,471
305
POTRERO HILL ENERGY PRODCERS LLC
0.00000
0.00000
63,121
7,869,023
7,869,023
306
POWEREX SHAPING FIRMING
0.00000
0.00000
1,553,805
1,553,805
307
PUTAH CREEK SOLAR FARMS
0.00000
0.00000
4,706
559,128
559,128
308
REDWOOD 4 SOLAR FARM
0.00000
0.00000
50,557
3,059,308
3,059,308
309
RIPON COGENERATION LLC
0.00000
0.00000
3,463
2,014,950
44,227
2,059,177
310
RISING TREE WIND FARM II LLC - RAM 4
0.00000
0.00000
56,129
3,451,960
3,451,960
311
ROCK CREEK HYDRO
0.00000
0.00000
1,538
131,064
131,064
312
SALMON CREEK HYDROELECTRIC
0.00000
0.00000
1,765
195,997
195,997
313
SAN JOSE CLEAN ENERGY
0.00000
0.00000
157,040
157,040
314
SAN JOSE WATER COX AVE HYDRO
0.00000
0.00000
291
35,294
35,294
315
SAN LUIS BYPASS
0.00000
0.00000
807
84,869
84,869
316
SANTA MARIA II LFG POWER PLANT
0.00000
0.00000
5,574
555,481
555,481
317
SEMPRA GENERATION EEI
0.00000
0.00000
39,000
39,000
318
SEMPRA MESQUITE SOLAR
0.00000
0.00000
392,125
61,771,043
61,771,043
319
SHAFTER SOLAR LLC RAM 3
0.00000
0.00000
50,794
4,831,287
4,831,287
320
SHELL ENERGY NORTH AMERICA
0.00000
0.00000
500
402,240
6,978
395,262
321
SHILOH I WIND
0.00000
0.00000
178,304
9,869,468
9,869,468
322
SHILOH I WIND PROJECT LLC
0.00000
0.00000
6,183
352,559
352,559
323
SHILOH II WIND (AKA ENXCO)
0.00000
0.00000
39,527
3,434,919
3,434,919
324
SHILOH II WIND PROJECT
0.00000
0.00000
345,755
30,478,099
30,478,099
325
SHILOH III (ENXCO)
0.00000
0.00000
9,190
1,054,521
1,054,521
326
SHILOH III WIND PROJECT
0.00000
0.00000
268,922
30,867,189
30,867,189
327
SHILOH IV
0.00000
0.00000
293,263
26,407,778
26,407,778
328
SIERRA GREEN ENERGY LLC
0.00000
0.00000
134
16,140
16,140
329
SIERRA PACIFIC INDUSTRIES
0.00000
0.00000
335,550
32,140,793
634,866
31,505,927
330
SIERRA PACIFIC POWER TSA
0.00000
0.00000
24,030
24,030
331
SILICON VALLEY CLEAN ENERGY AUTHORITY
0.00000
0.00000
200,000
3,390,000
3,390,000
332
SILICON VALLEY CLEAN ENERGY EEI
0.00000
0.00000
10,635,980
10,635,980
333
SILVER SPRINGS
0.00000
0.00000
1,890
198,672
198,672
334
SMUD WSPP
0.00000
0.00000
4,318,830
4,318,830
335
SO CAL EDISON EEI AGREEMENT
0.00000
0.00000
1,510,000
1,510,000
336
SONOMA CLEAN POWER AUTHORITY
0.00000
0.00000
1,945,305
1,945,305
337
SOUTH FEATHER WATER AND POWER AGENCY
0.00000
0.00000
234,421
3,376,794
9,033,377
12,410,171
338
SOUTH FEATHER WATER AND POWER AGENCY -
0.00000
0.00000
17,463
242,902
1,016,177
1,259,079
339
SOUTH SUTTER WATER DISTRICT
0.00000
0.00000
28
2,342
2,342
340
SR Solis Oro Loma Teresina Solar Proje
0.00000
0.00000
26,244
1,291,908
1,291,908
341
SR Solis Oro Loma Teresina Solar Proje
0.00000
0.00000
26,032
1,280,840
1,280,840
342
STARWOOD POWER MIDWAY, LLC
0.00000
0.00000
49,957
13,465,564
785,524
14,251,088
343
SUN HARVEST SOLAR, LLC (NDP1)
0.00000
0.00000
3,060
303,138
303,138
344
SUNRAY 2
0.00000
0.00000
59,938
3,578,614
3,578,614
345
SUNRISE POWER COMPANY LLC
0.00000
0.00000
14,767,200
14,767,200
346
SUTTERS MILL HYDROELECTRIC PLANT
0.00000
0.00000
723
75,003
75,003
347
TESORO REFINING & MARKETING LLC
0.00000
0.00000
90,266
779,462
4,937,060
5,716,522
348
THE ENERGY AUTHORITY - BU
0.00000
0.00000
89,920
89,920
349
THE ENERGY AUTHORITY EEI
0.00000
0.00000
1,213,300
1,213,300
350
THREE FORKS
0.00000
0.00000
5,210
519,304
519,304
351
TOPAZ SOLAR FARM
0.00000
0.00000
1,646,016
217,496,672
731
217,497,403
352
TORO SLO LANDFILL
0.00000
0.00000
10,244
1,143,956
1,143,956
353
TRANQUILLITY 8 AMARILLO
0.00000
0.00000
60,257
3,659,933
3,659,933
354
TRANSALTA ENREGY MARKETING US
0.00000
0.00000
538,274
549,550
20,874,970
20,325,420
355
TUNNEL HILL HYDRO
0.00000
0.00000
2,424
237,217
237,217
356
TWIN VALLEY HYDRO
0.00000
0.00000
1,449
166,971
166,971
357
VANTAGE WIND (POWEREX S&F)
0.00000
0.00000
193,088
9,315,820
9,122,732
358
VANTAGE WIND ENERGY LLC
0.00000
0.00000
243,974
24,998,512
1,524,000
23,474,512
359
VASCO WINDS (NEXTERA)
0.00000
0.00000
233,730
25,248,586
25,248,586
360
VINTNER SOLAR PROJECT
0.00000
0.00000
3,679
538,161
538,161
361
WADHAM ENERGY LP
0.00000
0.00000
57,290
4,881,747
4,881,747
362
WATER WHEEL RANCH
0.00000
0.00000
1,817
195,412
195,412
363
WECC WREGIS Fees
0.00000
0.00000
117,491
117,491
364
WEST ANTELOPE - RAM 1
0.00000
0.00000
39,130
3,413,748
3,413,748
365
WESTERN ANTELOPE BLUE SKY RANCH A - RA
0.00000
0.00000
53,901
3,693,052
3,693,052
366
WESTLANDS SOLAR FARMS LLC
0.00000
0.00000
43,794
5,747,956
5,747,956
367
WESTSIDE SOLAR
0.00000
0.00000
53,328
3,351,144
3,351,144
368
WHEELABRATOR SHASTA BIOMASS
0.00000
0.00000
3,300
3,300
369
WHEELABRATOR SHASTA BIORAM
0.00000
0.00000
6,000
6,000
370
WHITE RIVER SOLAR 2
0.00000
0.00000
49,361
4,874,910
4,874,910
371
WHITE RIVER SOLAR CED
0.00000
0.00000
49,923
7,689,785
7,689,785
372
WIND RESOURCE 1 (CALWIND) - RAM 1
0.00000
0.00000
14,005
1,041,388
1,041,388
373
WIND RESOURCE 2 (CALWIND) - RAM 2
0.00000
0.00000
47,599
3,557,582
3,557,582
374
WOLFSEN BYPASS FIT
0.00000
0.00000
2,892
289,593
289,593
375
WOODLAND BIOMASS
0.00000
0.00000
190,679
19,358,392
19,358,392
376
WOODMERE SOLAR RAM 4
0.00000
0.00000
35,627
2,574,253
2,574,253
377
YCWA MINI HYDRO
0.00000
0.00000
1,161
126,572
126,572
378
YOLO COUNTY GRASSLAND 3
0.00000
0.00000
2,049
259,464
259,464
379
YOLO COUNTY GRASSLAND 4
0.00000
0.00000
2,199
279,869
279,869
380
ZERO WASTE ENERGY DEVELOPMENT COMPANY
0.00000
0.00000
4,380
570,019
1,643
568,376
381
Pipeline charges
0.00000
0.00000
382
RUBY PIPELINE
0.00000
0.00000
12,686,997
12,686,997
383
WILLIAMS FIELD SERVICES -
0.00000
0.00000
6,325
6,325
384
SOUTHERN CA GAS - BU
0.00000
0.00000
10,762
10,762
385
Other charges
0.00000
0.00000
386
Irrigation districts
0.00000
0.00000
7,707
9,010,298
9,010,298
387
Liberty Utilities
0.00000
0.00000
5,040
862,378
862,378
388
ISO charges for storage cost
0.00000
0.00000
220,207
220,207
389
ISO charges ( net of storage cost but
0.00000
0.00000
5,863,083
257,845,224
257,845,224
390
Gas purchases, storage cost & forex
0.00000
0.00000
99,908,760
99,908,760
391
CARB fees
0.00000
0.00000
620,611
620,611
392
Consultancy fees
0.00000
0.00000
338,215
338,215
393
Gas Hedges & brokers fees
0.00000
0.00000
18,364,404
18,364,404
394
RECS from customers
0.00000
0.00000
395
(a)
Rounding issues in columns l
1,906
1,906
15 TOTAL
(b)(c)
31,325,610
701,694,986
2,418,783,649
376,365,951
3,496,844,586


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityProvidingPurchasedPower

The original entries in column l were in two decimal places, which the FERC software rounds automatically to whole numbers. The entry here is an adjustment to present the correct total.

(b) Concept: MegawattHoursPurchasedOtherThanStorage

For purposes only of accounting for the total energy that went through the Utility's electric system, the MWH for Direct Access ("DA") is 30,549,791 MWH. It should be noted that DA and DWR megawatts are not Utility purchases and were reported here only because page 401 of the Form 1 does not have any other available line where DA and DWR deliveries can be shown more appropriately.

 

The Utility acts as a pass-through entity for electricity purchased by the DWR that is sold to the Utility's customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from electricity revenue amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers, priced at the related CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility's electricity revenues in its Statement of Income.

(c) Concept: MegawattHoursPurchasedOtherThanStorage
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 10, Column: b, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as "wheeling")
  1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
  3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c).
  4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided.
  6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract.
  7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
  8. Report in column (i) and (j) the total megawatthours received and delivered.
  9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively.
  11. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Line No.
PaymentByCompanyOrPublicAuthority
Payment By (Company of Public Authority) (Footnote Affiliation)
(a)
TransmissionEnergyReceivedFromCompanyOrPublicAuthorityName
Energy Received From (Company of Public Authority) (Footnote Affiliation)
(b)
TransmissionEnergyDeliveredToCompanyOrPublicAuthorityName
Energy Delivered To (Company of Public Authority) (Footnote Affiliation)
(c)
StatisticalClassificationCode
Statistical Classification
(d)
RateScheduleTariffNumber
Ferc Rate Schedule of Tariff Number
(e)
TransmissionPointOfReceipt
Point of Receipt (Substation or Other Designation)
(f)
TransmissionPointOfDelivery
Point of Delivery (Substation or Other Designation)
(g)
BillingDemand
Billing Demand (MW)
(h)
TransmissionOfElectricityForOthersEnergyReceived
Megawatt Hours Received
(i)
TransmissionOfElectricityForOthersEnergyDelivered
Megawatt Hours Delivered
(j)
Demand Charges ($)
(k)
Energy Charges ($)
(l)
Other Charges ($)
(m)
RevenuesFromTransmissionOfElectricityForOthers
Total Revenues ($) (k+l+m)
(n)
1
TRANSMISSION AGENCY OF
2
(a)
NORTHERN CALIFORNIA (TANC)
Various
Various
Midway
Various
233
366,570
359,638
1,845,837
1,845,837
35 TOTAL
233
366,570
359,638
1,845,837
1,845,837


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

Other Charges represent booking estimate adjustments. In September 2003 the Utility changed billing methodology using energy as billing determinants rather than contract demand. The change was pursuant to the TO6 Settlement Agreement under FERC Docket No. ER03-666-000.

 

Transmission is provided under the Midway Transmission Service.

 

Recorded here are the Midway Transmission Service data for TANC members which include Modesto Irrigation District, Sacramento Municipal Utility District, City of Redding, and the Turlock Irrigation District.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY BY ISO/RTOs
  1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO.
  2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a).
  3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and AD- Out-of-Period Adjustments. Use this code for any accounting adjustments or “true-ups” for service provided in prior reporting periods. Provide an explanation in a footnote for each adjustment. See General Instruction for definitions of codes.
  4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided.
  5. In column (d) report the revenue amounts as shown on bills or vouchers.
  6. Report in column (e) the total revenues distributed to the entity listed in column (a).
Line No.
Payment Received by (Transmission Owner Name)
(a)
Statistical Classification
(b)
FERC Rate Schedule or Tariff Number
(c)
Total Revenue by Rate Schedule or Tariff
(d)
Total Revenue
(e)
1
NONE
40
TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
  1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter.
  2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported.
  3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
    FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
  4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
  5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
  6. Enter ""TOTAL"" in column (a) as the last line.
  7. Footnote entries and provide explanations following all required data.
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
Line No.
NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers
Name of Company or Public Authority (Footnote Affiliations)
(a)
StatisticalClassificationCode
Statistical Classification
(b)
TransmissionOfElectricityByOthersEnergyReceived
MegaWatt Hours Received
(c)
TransmissionOfElectricityByOthersEnergyDelivered
MegaWatt Hours Delivered
(d)
DemandChargesTransmissionOfElectricityByOthers
Demand Charges ($)
(e)
EnergyChargesTransmissionOfElectricityByOthers
Energy Charges ($)
(f)
OtherChargesTransmissionOfElectricityByOthers
Other Charges ($)
(g)
ChargesForTransmissionOfElectricityByOthers
Total Cost of Transmission ($)
(h)
1
CALIFORNIA-OREGON
2
TRANSMISSION PROJECT
(c)
351,510
351,510
3
PACIFICORP
(a)
149,118
(d)
89,102
238,220
4
SACRAMENTO MUNICIPAL
5
UTILITY DISTRICT
6
WESTERN AREA POWER
7
ADMINISTRATION
(b)
2,256
2,256
8
CALIFORNIA-OREGON
9
INTERTIE
(e)
357,499
357,499
10
OTHER
TOTAL
151,374
798,111
949,485


FOOTNOTE DATA

(a) Concept: DemandChargesTransmissionOfElectricityByOthers

Represents payments for lease of transmission capacity.

(b) Concept: DemandChargesTransmissionOfElectricityByOthers

Represents payments for lease of transmission capacity.

(c) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for operations and maintenance costs.

(d) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for operations and maintenance costs.

(e) Concept: OtherChargesTransmissionOfElectricityByOthers

Represents payments for administrative costs of scheduling services provided by the California Independent Systems Operator (CAISO).


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line No.
Description
(a)
Amount
(b)
1
IndustryAssociationDues
Industry Association Dues
7
2
NuclearPowerResearchExpenses
Nuclear Power Research Expenses
3
OtherExperimentalAndGeneralResearchExpenses
Other Experimental and General Research Expenses
4
PublicationAndDistributionExpensesForSecuritiesToStockholders
Pub and Dist Info to Stkhldrs...expn servicing outstanding Securities
5
OtherMiscellaneousGeneralExpenses
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
6
Clearing Account Adjustments
935,948
7
Intervenor Compensation
6,062,538
8
MCI-PG&E Exchange Rights
691,661
9
Bank Service Fees
3,097,911
10
Consulting Serv, Outside Attorney Fees, Contracts
220,882
11
Union Negotiation Adjustment
164,631
12
Non-PO Credit Memo's
49,525
13
Misc cash receipt (recovery of unclaimed funds)
86,289
14
Write off from miscellaneous reconciliations
20,072
15
Other miscellaneous adjustments
282
46
MiscellaneousGeneralExpenses
TOTAL
11,017,410


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Depreciation and Amortization of Electric Plant (Account 403, 404, 405)
  1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405).
  2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
  3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year.
    Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used.
    In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used.
    For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
  4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.
A. Summary of Depreciation and Amortization Charges
Line No.
FunctionalClassificationAxis
Functional Classification
(a)
DepreciationExpenseExcludingAmortizationOfAcquisitionAdjustments
Depreciation Expense (Account 403)
(b)
DepreciationExpenseForAssetRetirementCostsExcludingAmortizationgOfAcquisitionAdjustments
Depreciation Expense for Asset Retirement Costs (Account 403.1)
(c)
AmortizationOfLimitedTermPlantOrProperty
Amortization of Limited Term Electric Plant (Account 404)
(d)
AmortizationOfOtherElectricPlant
Amortization of Other Electric Plant (Acc 405)
(e)
DepreciationAndAmortization
Total
(f)
1
Intangible Plant
2,613,762
2,613,762
2
Steam Production Plant
20,001,934
20,001,934
3
Nuclear Production Plant
263,150,322
38,731,572
301,881,894
4
Hydraulic Production Plant-Conventional
75,375,746
4,752,000
80,127,746
5
Hydraulic Production Plant-Pumped Storage
12,377,607
2,280,000
14,657,607
6
Other Production Plant
47,195,594
47,195,594
7
Transmission Plant
305,450,082
305,450,082
8
Distribution Plant
1,217,489,436
1,217,489,436
9
Regional Transmission and Market Operation
10
General Plant
30,605,965
30,605,965
11
Common Plant-Electric
149,778,194
177,029,941
326,808,135
12
TOTAL
2,121,424,880
179,643,703
45,763,572
2,346,832,155
B. Basis for Amortization Charges
The basis used to compute the charges is the ending plant balance. The basis is different from the preceding year due to net plant additions throughout the year. The rates have been updated in accordance with 2017 GRC authorized rates. The rates used to compute amortization charges for ‘Intangible Plant – Electric’ (Account 404) are as follows: EIP30201 Intangible Plant: Franchise 2.19%; EIP30301 Intangible Plant: USBR 0%; EIP30303 Intangible Plant: Software 2.11% The rates used to compute amortization charges for ‘Common Plant – Electric’ (Account 404) are as follows: CMP30302 Intangible Plant: Software 21.45%; CMP30304 Intangible Plant: Software 6.61% For FERC reporting purposes, common amortization expense is allocated to electric and gas amortization as common amortization expense is not reported on the FERC forms. The rate used to allocate the common amortization expense to electric is 64.65%. Amortization of the Other Electric Plant (Account 405) - These amortization amounts represent the 2017 GRC authorized amounts to record for the recovery of the URG regulatory asset. In connection with the Chapter 11 Settlement Agreement, the CPUC authorized the Utility to recover $1.2 billion of costs related to the Utility's retained generation assets. The individual components of these regulatory assets are being amortized over the respective lives of the underlying generation facilities or recovery period, consistent with the period over which the related revenues are recognized.
C. Factors Used in Estimating Depreciation Charges
Line No.
AccountNumberFactorsUsedInEstimatingDepreciationCharges
Account No.
(a)
DepreciablePlantBase
Depreciable Plant Base (in Thousands)
(b)
UtilityPlantEstimatedAverageServiceLife
Estimated Avg. Service Life
(c)
UtilityPlantNetSalvageValuePercentage
Net Salvage (Percent)
(d)
UtilityPlantAppliedDepreciationRate
Applied Depr. Rates (Percent)
(e)
MortalityCurveType
Mortality Curve Type
(f)
UtilityPlantWeightedAverageRemainingLife
Average Remaining Life
(g)
12
0 years
0 years
13
4,801
0 years
2.18
SQ
0 years
14
113,671
(a)
75 years
3.46
R1
(be)
20 years
15
277,962
(b)
50 years
3.69
R1
(bf)
19 years
16
0 years
0 years
17
257,380
(c)
40 years
3.56
R2.5
(bg)
19 years
18
52,626
(d)
45 years
3.55
R2.5
(bh)
20 years
19
28,349
(e)
40 years
3.77
S0.5
(bi)
18 years
20
734,789
0 years
0 years
21
0 years
0 years
22
17,311
0 years
1.9
SQ
0 years
23
525,846
(f)
80 years
2
1.72
R2
(bj)
14 years
24
2,124,218
(g)
120 years
3
1.6
R2.5
(bk)
18 years
25
1,007,802
(h)
81 years
3
3.1
R1
(bl)
15 years
26
296,609
(i)
65 years
6
3.03
R1.5
(bm)
16 years
27
102,422
(j)
60 years
9
3.39
S0.5
(bn)
16 years
28
93,136
(k)
88 years
2
2.48
S1.5
(bo)
17 years
29
4,167,344
0 years
0 years
30
0 years
0 years
31
1,085,290
(l)
100 years
1
1.55
R1
(bp)
6 years
32
3,569,330
(m)
65 years
1
2.7
S1
(bq)
6 years
33
1,172,601
(n)
50 years
1
1.54
S2
(br)
6 years
34
844,039
(o)
75 years
1.6
R1.5
(bs)
6 years
35
1,152,130
(p)
50 years
1
5.69
S1
(bt)
6 years
36
7,823,390
0 years
0 years
37
0 years
0 years
38
3,121
0 years
0.64
SQ
0 years
39
210,804
(q)
59 years
3.69
R1,SQ
(bu)
20 years
40
11,271
(r)
50 years
3.69
R1
(bv)
19 years
41
227,881
(s)
40 years
3.57
R2.5
(bw)
20 years
42
353,878
(t)
27 years
4.35
R2.5,SQ
(bx)
18 years
43
213,715
(u)
31 years
5.71
R2.5,S2.5,SQ
(by)
16 years
44
98,646
(v)
35 years
3.84
S0.5,SQ
(bz)
18 years
45
1,119,316
0 years
0 years
46
0 years
0 years
47
247,241
(w)
42 years
4.06
R4
(ca)
26 years
48
536,335
(x)
65 years
20
1.8
R3
(cb)
56 years
49
6,478,163
(y)
2 years
0.08
R1.5
(cc)
1 year
50
961,640
(z)
75 years
66
2.25
R4
(cd)
55 years
51
1,384,181
(aa)
52 years
65
2.99
R1.5
(ce)
43 years
52
1,670,014
(ab)
65 years
70
2.57
R2
(cf)
49 years
53
511,098
(ac)
65 years
1.52
R4
(cg)
54 years
54
274,014
(ad)
55 years
10
1.99
R3
(ch)
42 years
55
103,204
(ae)
60 years
10
1.91
R1.5
(ci)
51 years
56
12,165,890
0 years
0 years
57
0 years
0 years
58
4,891
(af)
65 years
1.43
R3
(cj)
6 years
59
89,972
(ag)
98 years
19
7.05
R2
(ck)
12 years
60
94,863
0 years
0 years
61
0 years
0 years
62
122,527
(ah)
41 years
2.12
SQ
(cl)
19 years
63
323,045
(ai)
65 years
20
1.78
R3
(cm)
46 years
64
3,514,657
(aj)
46 years
40
3.06
R1.5
(cn)
32 years
65
33,497
(ak)
15 years
6.46
R2,S3
(co)
9 years
66
4,847,361
(al)
44 years
150
6.03
R1.5
(cp)
31 years
67
4,776,896
(am)
46 years
125
5.05
R2
(cq)
32 years
68
3,001,225
(an)
62 years
50
2.6
R4
(cr)
44 years
69
4,804,342
(ao)
47 years
65
3.35
R3
(cs)
31 years
70
3,790,010
(ap)
32 years
28
4.4
R2.5,R3
(ct)
21 years
71
3,423,955
(aq)
47 years
67
3.5
R2.5,R4
(cu)
28 years
72
1,201,281
(ar)
20 years
15
6.21
R1.5
(cv)
13 years
73
28,071
(as)
39 years
1
0.09
S1
(cw)
5 years
74
895
(at)
25 years
L1
0 years
75
254,680
(au)
28 years
23
3.25
R0.5,S1.5,L0,S1
(cx)
10 years
76
30,122,442
0 years
0 years
77
0 years
0 years
78
415
(av)
59 years
2.74
SQ
(cy)
31 years
79
11,777
(aw)
50 years
10
1.62
R2
(cz)
30 years
80
10,927
(ax)
20 years
6.2
SQ
(da)
11 years
81
145,209
(ay)
25 years
3.85
SQ
(db)
17 years
82
15,907
(az)
20 years
5.37
SQ
(dc)
13 years
83
0 years
0 years
84
351,873
(ba)
15 years
6.25
SQ
(dd)
12 years
85
25,736
(bb)
20 years
13.04
SQ
(de)
17 years
86
561,844
0 years
0 years
87
0 years
0 years
88
4,504
(bc)
20 years
5.23
SQ
(df)
16 years
89
15,863
(bd)
20 years
5.39
SQ
(dg)
16 years
90
20,367
0 years
0 years
91
56,810,245
0 years
0 years


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(b) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(c) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(d) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 45
(e) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(f) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 80
(g) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 120
(h) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 81
(i) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(j) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(k) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 88
(l) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 100
(m) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(n) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(o) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(p) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(q) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 59
(r) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(s) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(t) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 27
(u) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 31
(v) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(w) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 42
(x) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(y) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 2
(z) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(aa) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 52
(ab) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(ac) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(ad) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 55
(ae) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(af) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(ag) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 98
(ah) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 41
(ai) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(aj) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 46
(ak) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(al) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 44
(am) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 46
(an) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 62
(ao) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 47
(ap) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 32
(aq) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 47
(ar) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(as) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 39
(at) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(au) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 28
(av) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 59
(aw) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(ax) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ay) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(az) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(ba) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(bb) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bc) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bd) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(be) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.7
(bf) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 18.9
(bg) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.3
(bh) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.7
(bi) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 18.2
(bj) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 13.8
(bk) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 18.3
(bl) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 14.6
(bm) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 15.7
(bn) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 15.6
(bo) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 17.1
(bp) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 6.3
(bq) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 5.9
(br) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 5.6
(bs) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 6.1
(bt) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 6.2
(bu) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.6
(bv) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19
(bw) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.5
(bx) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 18.4
(by) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 15.6
(bz) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 18.3
(ca) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 26.3
(cb) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 55.5
(cc) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 0.8
(cd) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 55.3
(ce) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 42.6
(cf) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 49.3
(cg) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 53.8
(ch) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 42
(ci) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 50.9
(cj) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 6.4
(ck) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 12.3
(cl) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 19.3
(cm) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 46.5
(cn) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 32.5
(co) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 9.2
(cp) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 30.9
(cq) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 31.6
(cr) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 43.8
(cs) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 30.8
(ct) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 21
(cu) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 27.5
(cv) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 13.2
(cw) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 4.6
(cx) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 10
(cy) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 30.9
(cz) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 30.4
(da) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 10.9
(db) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 17.3
(dc) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 12.9
(dd) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 12.5
(de) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 17.2
(df) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 16.5
(dg) Concept: UtilityPlantWeightedAverageRemainingLife
Original value: 15.9

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
REGULATORY COMMISSION EXPENSES
  1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
  2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.
  3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
  4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
  5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
EXPENSES INCURRED DURING YEAR
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 for Current Year
(d)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred in Account 182.3 at Beginning of Year
(e)
NameOfDepartmentRegulatoryCommissionExpensesCharged
Department
(f)
AccountNumberRegulatoryCommissionExpensesCharged
Account No.
(g)
RegulatoryCommissionExpenses
Amount
(h)
RegulatoryCommissionExpensesDeferredToOtherRegulatoryAssets
Deferred to Account 182.3
(i)
DeferredRegulatoryCommissionExpensesAmortizedInContraAccount
Contra Account
(j)
DeferredRegulatoryCommissionExpensesAmortized
Amount
(k)
OtherRegulatoryAssetsRegulatoryCommissionExpenses
Deferred to Account 182.3 End of Year
(l)
1
Annual fees paid for Diablo Canyon Power Plant
2
in accordance with Part 171
3
Docket 5000133
47,000
47,000
47,000
4
Docket 5000275
4,493,628
4,493,628
4,493,628
5
Docket 5000323
4,493,628
4,493,628
4,493,628
7
Fees paid for Diablo Canyon Power Plant
8
for inspection, license renewal, operator
9
examination in accordance with Part 170
10
Docket 5000275
1,020,279
1,020,279
1,020,279
11
Docket 5000323
1,072,415
1,072,415
1,072,415
12
General Accrual
195,000
195,000
195,000
14
Fees paid for Diablo Canyon Power Plant
15
for inspection, license renewal, operator
16
examination in accordance with Part 170
17
Docket 5000275
61,766
61,766
61,766
18
Docket 5000323
66,415
66,415
66,415
19
General Accrual
100,000
100,000
100,000
21
Fees paid for Diablo Canyon Power Plant
22
for inspection, license renewal, operator
23
examination in accordance with Part 170
24
Docket 7200026
69,498
69,498
69,498
26
Fees paid for Diablo Canyon Power Plant
27
for inspection, license renewal, operator
28
examination in accordance with Part 171
29
Docket 5000275
46,122
46,122
30
Docket 5000323
46,122
46,122
31
General Accrual
40,000
40,000
33
Annual fees paid for Humubolt Bay Power Plant
34
in accordance with Part 171
35
Docket 5000133
153,500
153,500
153,500
37
*All paid to US Nuclear Regulatory Commission
46
TOTAL
11,315,373
11,315,373
11,183,129


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
  1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D and D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D and D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts).
  2. Indicate in column (a) the applicable classification, as shown below:
    Classifications:
    1. Electric R, D and D Performed Internally:
      1. Generation
        1. hydroelectric
          1. Recreation fish and wildlife
          2. Other hydroelectric
        2. Fossil-fuel steam
        3. Internal combustion or gas turbine
        4. Nuclear
        5. Unconventional generation
        6. Siting and heat rejection
      2. Transmission
        1. Overhead
        2. Underground
      3. Distribution
      4. Regional Transmission and Market Operation
      5. Environment (other than equipment)
      6. Other (Classify and include items in excess of $50,000.)
      7. Total Cost Incurred
    2. Electric, R, D and D Performed Externally:
      1. Research Support to the electrical Research Council or the Electric Power Research Institute
      2. Research Support to Edison Electric Institute
      3. Research Support to Nuclear Power Groups
      4. Research Support to Others (Classify)
      5. Total Cost Incurred
  3. Include in column (c) all R, D and D items performed internally and in column (d) those items performed outside the company costing $50,000 or more, briefly describing the specific area of R, D and D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D and D activity.
  4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e).
  5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year.
  6. If costs have not been segregated for R, D and D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by ""Est.""
  7. Report separately research and related testing facilities operated by the respondent.
AMOUNTS CHARGED IN CURRENT YEAR
Line No.
ResearchDevelopmentAndDemonstrationClassification
Classification
(a)
ResearchDevelopmentAndDemonstrationDescription
Description
(b)
ResearchDevelopmentAndDemonstrationCostsIncurredInternally
Costs Incurred Internally Current Year
(c)
ResearchDevelopmentAndDemonstrationCostsIncurredExternally
Costs Incurred Externally Current Year
(d)
AccountNumberForResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Account
(e)
ResearchDevelopmentAndDemonstrationCosts
Amounts Charged In Current Year: Amount
(f)
ResearchDevelopmentAndDemonstrationExpenditures
Unamortized Accumulation
(g)
1
A2, A3
Electric Program Investment Charge
10,284,310
250,978
2
193,037
3
9,483,988
4
742,381
5
A2, A3
Customer Energy Services -
3,501,062
27,430
6
Cyber Security and Grid Innovation
3,416,438
7
23,918
8
81,112


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
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. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.

Line No.
Classification
(a)
Direct Payroll Distribution
(b)
Allocation of Payroll Charged for Clearing Accounts
(c)
Total
(d)
1
SalariesAndWagesElectricAbstract
Electric
2
SalariesAndWagesElectricOperationAbstract
Operation
3
SalariesAndWagesElectricOperationProduction
Production
330,993,100
4
SalariesAndWagesElectricOperationTransmission
Transmission
79,824,930
5
SalariesAndWagesElectricOperationRegionalMarket
Regional Market
6
SalariesAndWagesElectricOperationDistribution
Distribution
175,719,058
7
SalariesAndWagesElectricOperationCustomerAccounts
Customer Accounts
113,609,934
8
SalariesAndWagesElectricOperationCustomerServiceAndInformational
Customer Service and Informational
56,998,283
9
SalariesAndWagesElectricOperationSales
Sales
651,164
10
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
216,549,578
11
SalariesAndWagesElectricOperation
TOTAL Operation (Enter Total of lines 3 thru 10)
974,346,047
12
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
13
SalariesAndWagesElectricMaintenanceProduction
Production
99,428,025
14
SalariesAndWagesElectricMaintenanceTransmission
Transmission
38,444,457
15
SalariesAndWagesElectricMaintenanceRegionalMarket
Regional Market
16
SalariesAndWagesElectricMaintenanceDistribution
Distribution
171,069,015
17
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
3
18
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 13 thru 17)
308,941,500
19
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
20
SalariesAndWagesElectricProduction
Production (Enter Total of lines 3 and 13)
430,421,125
21
SalariesAndWagesElectricTransmission
Transmission (Enter Total of lines 4 and 14)
118,269,387
22
SalariesAndWagesElectricRegionalMarket
Regional Market (Enter Total of Lines 5 and 15)
23
SalariesAndWagesElectricDistribution
Distribution (Enter Total of lines 6 and 16)
346,788,073
24
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (Transcribe from line 7)
113,609,934
25
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (Transcribe from line 8)
56,998,283
26
SalariesAndWagesElectricSales
Sales (Transcribe from line 9)
651,164
27
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Enter Total of lines 10 and 17)
216,549,581
28
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
1,283,287,547
1,283,287,547
29
SalariesAndWagesGasAbstract
Gas
30
SalariesAndWagesGasOperationAbstract
Operation
31
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
32
SalariesAndWagesGasOperationProductionNaturalGas
Production-Nat. Gas (Including Expl. And Dev.)
2,634,683
33
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
34
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
5,539,415
35
SalariesAndWagesGasOperationTransmission
Transmission
96,675,038
36
SalariesAndWagesGasOperationDistribution
Distribution
158,177,895
58
SalariesAndWagesGasCustomerAccounts
Customer Accounts
74,115,974
38
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
14,454,403
60
SalariesAndWagesGasSales
Sales
608,866
40
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
105,505,118
41
SalariesAndWagesGasOperation
TOTAL Operation (Enter Total of lines 31 thru 40)
457,711,392
42
SalariesAndWagesGasMaintenanceAbstract
Maintenance
43
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
44
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production-Natural Gas (Including Exploration and Development)
249,993
45
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
46
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
1,552,205
47
SalariesAndWagesGasMaintenanceTransmission
Transmission
55,191,848
48
SalariesAndWagesGasMaintenanceDistribution
Distribution
84,850,684
49
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
1
50
SalariesAndWagesGasMaintenance
TOTAL Maint. (Enter Total of lines 43 thru 49)
141,844,731
51
SalariesAndWagesGasOperationAndMaintenanceAbstract
Total Operation and Maintenance
52
SalariesAndWagesGasProductionManufacturedGas
Production-Manufactured Gas (Enter Total of lines 31 and 43)
53
SalariesAndWagesGasProductionNaturalGas
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,
2,884,676
54
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Enter Total of lines 33 and 45)
55
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of lines 31 thru
7,091,620
56
SalariesAndWagesGasTransmission
Transmission (Lines 35 and 47)
151,866,886
57
SalariesAndWagesGasDistribution
Distribution (Lines 36 and 48)
243,028,579
37
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Line 37)
74,115,974
38
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Line 38)
14,454,403
60
SalariesAndWagesGasSales
Sales (Line 39)
608,866
61
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Lines 40 and 49)
105,505,119
62
SalariesAndWagesGasOperationAndMaintenance
TOTAL Operation and Maint. (Total of lines 52 thru 61)
599,556,123
599,556,123
63
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
64
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
65
SalariesAndWagesOperationsAndMaintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
1,882,843,670
1,882,843,670
66
SalariesAndWagesUtilityPlantAbstract
Utility Plant
67
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
68
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
781,939,241
781,939,241
69
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
422,493,640
422,493,640
70
SalariesAndWagesUtilityPlantConstructionOther
Other (provide details in footnote):
(a)
158,619,223
158,619,223
71
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 68 thru 70)
1,363,052,104
1,363,052,104
72
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
73
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
65,534,708
65,534,708
74
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
25,198,754
25,198,754
75
SalariesAndWagesPlantRemovalOther
Other (provide details in footnote):
1,065,193
1,065,193
76
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 73 thru 75)
91,798,655
91,798,655
77
SalariesAndWagesOtherAccountsAbstract
Other Accounts (Specify, provide details in footnote):
78
SalariesAndWagesOtherAccountsDescription
Other Balance Sheet Salaries and Wages
13,605,364
13,605,364
79
SalariesAndWagesOtherAccountsDescription
Other Non-Operating Salaries and Wages
10,690,997
10,690,997
80
SalariesAndWagesOtherAccountsDescription
81
SalariesAndWagesOtherAccountsDescription
82
SalariesAndWagesOtherAccountsDescription
83
SalariesAndWagesOtherAccountsDescription
84
SalariesAndWagesOtherAccountsDescription
85
SalariesAndWagesOtherAccountsDescription
86
SalariesAndWagesOtherAccountsDescription
87
SalariesAndWagesOtherAccountsDescription
88
SalariesAndWagesOtherAccountsDescription
89
SalariesAndWagesOtherAccountsDescription
90
SalariesAndWagesOtherAccountsDescription
91
SalariesAndWagesOtherAccountsDescription
92
SalariesAndWagesOtherAccountsDescription
93
SalariesAndWagesOtherAccountsDescription
94
SalariesAndWagesOtherAccountsDescription
95
SalariesAndWagesOtherAccounts
TOTAL Other Accounts
24,296,361
24,296,361
96
SalariesAndWagesGeneralExpense
TOTAL SALARIES AND WAGES
3,361,990,790
3,361,990,790


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SalariesAndWagesUtilityPlantConstructionOther

Represents Common Plant


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
COMMON UTILITY PLANT AND EXPENSES
  1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
  2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used.
  3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation.
  4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization.
COMMON UTILITY PLANT IN SERVICE ------------------------------- Balance Transfers Balance Acct Beginning and End No. Description of Year Additions Retirements Adjustments of Year ---- ------------------- ------------- ----------- ------------ ----------- ------------- 301 Organization 132,411 997 0 (997) 132,411 302 Franchises/Consents 214,735 0 0 0 214,735 303 Intangible Plant 1,689,092,237 195,843,124 (290,220,071) 0 1,594,715,290 ------------- ----------- ------------ ----------- ------------- Total Intangible Plant 1,689,439,383 195,844,121 (290,220,071) (997) 1,595,062,436 ------------- ----------- ------------ ----------- ------------- 389 Land and Land Rights 91,241,687 13,145,387 0 (27,639) 104,359,435 ------------- ----------- ------------ ----------- ------------- 390 Structures and Improvements 1,657,025,235 174,589,367 (198,396) 0 1,831,416,206 391 Personal Computer Hardware 94,231,910 11,356,419 (32,650,708) 0 72,937,621 391 Office Machines 320,722,501 71,645,048 (70,923,780) 997 321,444,766 391 Office Furniture and Equipment 119,333,965 4,462,818 (2,568,691) 0 121,228,092 392 Transportation Equipment 1,068,627,787 53,641,339 (41,718,944) 0 1,080,550,182 393 Stores Equipment 9,418,244 307,799 (9,721) 0 9,716,322 394 Tools, Shop, and Garage Equipment 68,889,594 897,918 0 0 69,787,512 395 Laboratory Equipment 9,794,188 3,789,423 (160,165) 0 13,423,446 396 Power Operated Equipment 177,613,797 2,597,075 (3,126,781) 0 177,084,091 397 Communication Equipment 1,171,430,168 78,490,136 (33,491,788) 0 1,216,428,516 398 Miscellaneous Equipment 41,357,926 (12,288,261) (360,798) 0 28,708,867(a) 399 Other Tangible Property 679 0 0 0 679 ------------- ----------- ------------ ----------- ------------- Total Non-Landed 4,738,445,994 389,489,081 (185,209,772) 997 4,942,726,300 Total 6,519,127,064 598,478,589 (475,429,843) (27,639) 6,642,148,171 ------------- ----------- ------------ ----------- ------------- 101 Property Under Capital Leases 18,230,721 0 0 0 18,230,721 101 Plant Purchased/Sold 0 0 0 0 0 ------------- ----------- ------------ ----------- ------------- Total Common Utility Plant in Service6,537,357,785 598,478,589 (475,429,843) (27,639) 6,660,378,892 107 Construction Work in Progress - 398,724,501 101,003,688 0 (11,448,712) 488,279,477 Common Utility Plt. ------------- ----------- ------------ ----------- ------------- Total Common Utility Plant 6,936,082,286 699,482,277 (475,429,843) (11,476,351) 7,148,658,369 ============= =========== ============ =========== ============= NOTES: (a) Included in the 12/31/18 FERC account 398 plant balance is $13,874,119 in Operative CWIP. Operative CWIP is defined as capital orders that are less than 30 days of construction that remain in CWIP due to capital order settlement issues. Capital orders that are less than 30 days of construction should be classified as plant. Since we may not know the final settlement of operative CWIP orders, FERC account 398 is chosen as a temporary settlement until these orders have valid settlement rules. ALLOCATION OF COMMON UTILITY PLANT AND ACCUMULATED PROVISION FOR DEPRECIATION BASED ON THE COST SEPARATION ADOPTED BY THE CPUC -------------------------------------------- Description Total Electric Gas ----------- ------------- ------------- ------------- Common Utility Plant in Service (a) 6,660,378,892 4,306,079,230 2,354,299,662 Accumulated Provision for Depreciation (a) 2,742,082,239 1,779,611,373 962,470,866 ALLOCATION OF AD VALOREM TAXES APPLICABLE TO COMMON UTILITY PLANT BASED ON THE COST SEPARATION ADOPTED BY THE CPUC ------------------------------------------------ Amount Account 408 Charged ------------------------------ Description During Year Electric Gas ----------- ------------- ------------- ------------- Taxes Operative Property (b) 470,923,474 355,559,961 115,363,513 (from page 262-263) Common Utility Plant (a) 41,199,088 26,636,103 14,562,985 included in above amount NOTES: (a) 2018 allocations are based on the methodology of unbundling Common Plant as approved in the cost separation filing and adopted in the 2017 General Rate Case (GRC). Electric Gas ------------- ------------- Common Plant in Service Allocation Factors 64.65% 35.35% Common Plant Accumulated Depreciation Allocation Factors 64.90% 35.10% (b) Amounts are based on direct charges. Not included in the total was $486,744 charged to others. ALLOCATION OF DEPRECIATION EXPENSE APPLICABLE TO COMMON UTILITY PLANT BASED ON THE COST SEPARATION ADOPTED BY THE CPUC -------------------------------------------------------------- Amount Account 403 Charged ------------------------------ Description Account During Year Electric Gas ----------- ------- ------------- ------------- ------------- Depreciation 403 230,783,041 149,778,194 81,004,847 Amortization 404 272,773,407 177,029,941 95,743,465 ------------- ------------- ------------- Total 503,556,448 326,808,135 176,748,312 ============= ============= ============= ALLOCATION OF MAINTENANCE EXPENSES OF COMMON UTILITY PLANT BASED ON THE COST SEPARATION ADOPTED BY THE CPUC ------------------------------------------------------ Amount Account 935 Charged ------------------------------ Description During Year Electric Gas ----------- ------------- ------------- ------------- Maintenance of General Plant 6,979,178 4,725,363 2,253,815 Note: Operation expense data was not available. CONSTRUCTION WORK IN PROGRESS (CWIP) - COMMON (ACCOUNT 107) ----------------------------------------------------------- Description of Project Amount --------------------------------------- -------- 7086328 Merced SC - Building B RMC 25,470,786.81 70032940 ITSM Remedy Upgrade 11,233,417.20 74017024 SAP Roadmap Foundational Upgrade 10,634,902.32 7092050 77 Beale GO-8th,27th Flrs Refresh (IO) 9,531,565.98 70036182 CC2020 Salesforce - Cap 8,954,872.46 74017181 Endur Upgrade Ph2 8,122,463.71 7090505 Corp Security-Replacement of Legacy CCTV 7,818,043.41 7094507 Wildfire Helicopter - N605PG 7,740,308.76 7094508 Wildfire Helicopter - N606PG 7,740,308.74 7092090 Concord SC - Refresh Program - Area 2 7,648,206.39 7094505 Wildfire Helicopter - N603PG 7,336,051.00 7094506 Wildfire Helicopter - N604PG 7,336,051.00 70028908 DR - Meter Data Management System (MDMS) 7,145,571.08 7092306 Facility Asset Upkeep - Area 2 6,981,302.46 7091299 VCOC - B1 Expansion 6,940,572.18 7091625 System ETI-Trailer Upgr Pgrm (2017) 6,676,962.64 7092311 Facility Asset Upkeep - Area 6S 6,591,120.67 7090331 San Francisco SC - Security Program 6,443,961.41 7092307 Facility Asset Upkeep - Area 3 6,297,356.19 7091106 Merced LNG - Tanker Relocation 5,694,832.98 70035445 IO - SmartMeterSSN Transition PG&E (CAP) 5,342,738.14 70036866 MRAD Platform 2.0 Cap 5,309,965.30 70036060 IO - Cloud Enablement - Cloud Mgmt Pltfr 5,203,189.01 7092288 Service Center Refresh Program - Area 6 5,166,011.23 7093047 Stockton Mat'l Lease Optimization_B 5,055,443.63 7092292 Facility Asset Upkeep - GO 4,827,524.03 70035220 ST - Security Enclave (CAP) 4,766,238.02 70036224 Communication-FAN 4,715,963.42 70035405 Increase Self Service Adoption - Cap 4,629,065.40 7089806 Bay Area Program - GO (CAR 1C) 4,355,922.46 70036900 ARAD 3.0 Cap 4,231,497.54 70033583 OP: AMSM-Asset Mgmt Pltfrm & Srvcs (AMPS 4,223,627.20 7092045 SFGO - Conference Rooms Refresh (IO) 4,132,344.83 70034968 IO - Pure Flex Remediation 4,014,403.36 7092293 Burney SC - Security Program - Area 6 3,965,318.63 7091574 Network Improvements - Add Alternate 3,946,983.76 74017094 SQMD Replacement Phase 3 3,944,987.23 7091946 Stockton Regional Ofc-Upgrades (PH2)_PV 3,716,796.57 70037840 Locate & Mark (GRCGD) - CAP 3,665,922.84 7093670 CSO Security Upgrades (75 Sites) Ph2 3,456,134.91 7091451 Facility Asset Upkeep Break/Fix 3,347,134.46 7092785 DMS Upgrade 3,346,124.60 70035024 ST-Web Acc Mgmt (CA Sitemndr) Rep (CAP) 3,315,174.09 70035562 Meter Data Mgmt Sys Upgrade R1 - Cap 3,239,156.47 70033757 Substation Record and RecordKeeping Impr 3,188,932.09 7087511 Antioch SC - Renovation 3,184,128.72 7092312 Facility Asset Upkeep - Area 7 3,087,563.81 7092310 Facility Asset Upkeep - Area 6N 3,032,174.99 70035507 IO - ECP IP Trade Turret Infra Upgrd 3,024,454.11 70035661 DC - OSI PI Platform Capacity Phase 3 - 2,943,316.38 7092286 Bkfld,SMaria,TemplSC-Refresh Prog--Area4 2,942,751.94 7091572 GTCC Predictive Health Analytics 2,841,846.89 7091945 FM Energy Efficiency Upgrade Program 2,809,193.17 7093625 LOB Ofc Optimiz Pgm - Edenvale/SLO 2,747,715.36 7091785 77 Beale GO - Mech Upgrd - Flrs 11-15-16 2,742,656.54 7092289 Service Center Refresh Program - Area 7 2,721,779.88 74017086 FFMO CAP 2,717,338.21 70033741 Express Connects Cap 2,582,960.98 7092505 CSO Head Cashier Ofc Renovation Program 2,556,234.49 7092285 Service Center Refresh Program - Area 3 2,535,246.23 70036262 SSN Wildfire Data Queries (Cap) 2,460,391.13 70037185 Inspect and Maintain (AI 2.0) (ED) - Cap 2,453,971.22 70037184 Inspect and Maintain (AI 2.0) (GD) - CAP 2,446,393.33 70030413 Cyber: Windows XP Migration CAP Transmis 2,446,280.55 74017084 Enterprise Compliance Management Tool CA 2,434,730.46 7092287 Sonora SC - Refresh Program - Area 5 2,363,155.15 70037187 Inspect and Maintain (AI 2.0) (TO) - CAP 2,344,495.64 70036143 EES Ph2 (CAP) 2,281,640.83 7090825 Corp Security-SIS Replacement-Capital 2,230,695.03 74017099 Hat Creek Network Extension 2,183,672.96 7093946 Lemoore Flt - Mtc Bldg & Wash Station 2,182,500.73 70032961 CIP003-WP04A Low Impact Methodology 2,156,929.51 70037186 Inspect and Maintain (AI 2.0) (GTS) - CA 2,149,323.51 70033421 Corrective Maintenance (GRCED) - Cap 2,125,387.18 70033422 Corrective Maintenance (GRCGD) - Cap 2,116,197.53 7092265 San Francisco SC - Refresh Prog - Area 1 2,103,531.47 70033756 Bentley SAP Integration - Phase3 2,080,155.79 7092249 System - SC Security Program - Area 3 2,051,921.37 7091345 SFGO - Elec Upgrd (Controls & Alarms) 2,018,452.85 7092025 LOB Office Optimization Program 2,013,764.09 74017090 ESOMS Upgrade CAP 1,945,841.67 70037327 CWSP: WSOC Monitoring and Decision Supp 1,900,985.57 7092305 Facility Asset Upkeep - Area 1 1,875,462.36 70029346 Wesley Fiber Install 1,871,332.89 70037821 CES - Contact Ctr Hardware Purchases (C) 1,854,166.10 70035642 JUMP (Cap) 1,853,199.30 7093891 ADMS Phase 0 Cap 1,852,606.54 7090645 System ETI - Trailer Upgrade Program_C 1,762,524.79 74017091 DCPP Replace EDMS/RMS/Filenet PH2 1,743,552.37 7091573 GDCC Predictive Health Analytics 1,707,440.83 70035502 ST - 2018 Lifecycle Replacement (Cap) 1,653,969.13 70036261 Transmission Support Structures (CAP) 1,649,312.81 70036780 Trans Support Structures GRC (CAP) 1,642,866.33 70037462 IO - Digital Mobile Radio (DMR) Backend 1,591,359.00 70037463 CRCR Release 2 - BT CAP 1,575,854.66 70036222 Cybersecurity 1,567,244.26 7092308 Facility Asset Upkeep - Area 4 1,559,843.11 70029487 2015 Oracle DB_Audit Rem & Data Sec Enh 1,521,165.84 74016901 Consolidate PGEN PPM into EPPM. 1,460,029.77 7092290 Fresno CSO - Security Program - Area 4 1,380,382.06 74017920 NEWVMS CAP 1,318,768.86 70034495 Vulnerability Management Program 1,302,306.71 7090325 Auburn SC Regional GC Conversion 1,298,304.09 70038048 IO - Smart Meter Field Assets Lifecycle 1,252,096.23 74017496 Enabling Online HR CAP 1,240,525.51 70036482 ARI Enhancements Capital 1,207,324.60 70037086 IGP - SCADA -MT Top Radio Masters 1,185,705.94 7092294 Ukiah SC - Security Program - Area 7 1,171,966.04 70036940 EGI 2018 Tariff Changes 1,153,479.17 70037080 IO - Data Center Consolidation Storage 1,120,855.35 70032529 Linear Inspection (ED) - CAP 1,118,926.40 70026860 Table Mtn Sub Fiber Install 1,115,801.07 70036742 IO - WIFI Everywhere-Field Ph 2 - W2 1,095,457.86 7093893 CSO - Install Bullet Resistant Glass PH1 1,090,292.01 70035480 Automation of FAA Obstruction Evaluation 1,063,641.01 7092246 Antioch/Oakland SC-Security Prog Area 2 1,057,385.04 74017088 Lease Standard Implementation CAP 1,045,915.58 70037720 IO - D305 - D306 DMW Replacement 1,045,711.92 70035542 IO - WAN WAAS Optimization 1,025,360.53 74017560 Model Platform P5 CAP 1,020,949.65 7074466 Tracy Sub to Bethany Cmprsr Stn Fbr Bld 1,016,723.19 70035741 Heavy Bid to SAP (Cap) 1,003,075.36 70030697 D080 SLO SC to Black Butte 983,568.43 7092965 15 Sites - Critical Substations Tier 1 2 978,023.32 70036161 Compliance Asset Data Reporting (CAP) 958,844.68 70033549 Cyber SS ST - 3rd Party Security and Ris 914,743.22 70035447 DCPP Network Switch and WiFi Replacement 881,640.48 7091575 Network Improvements - Improve WAN 866,268.67 70032902 Fiber Cable - Sacramento Fiber Cable Rep 858,677.09 74018245 MII ESDER 2 847,067.71 70036021 Data Security Data De-Identification (Ca 843,225.95 70036042 DR - Set 9 Disaster Recovery Project (CA 831,368.32 74018242 MII Fall 2018 819,190.98 74017097 Power Gen Records Management - cap 780,516.66 7086212 77 Beale GO - Mech Upgrd(Fans 6-7-11-12) 754,044.31 7088763 Electric Storage Containers 744,535.16 70036027 Data Security Metrics, Inventory, Owners 739,402.95 70033814 Bentley-SAP Integration CAP ET Phase 3 731,456.15 70036360 CYME LoadSEER and EDPI Integration 731,070.41 70036023 Data Security DLP Expansion (Cap) 725,611.38 74017106 Kings-Crane Grounding and Bonding 724,383.82 70037540 IGP Communication-Control/Data Center v2 721,306.79 7083729 TO Radio System Expansion - Gato Ridge 718,959.93 70033419 Corrective Maintenance (TO) - Cap 707,929.99 70033420 Corrective Maintenance (GT&S) - Cap 707,929.99 70035023 Lvl 3 Lat Bld-Eastshore Sub 706,490.38 70035662 DC - OSI PI Platform Capacity Phase 3 - 681,375.73 74018957 FBS Upgrade 680,536.47 70033697 Gas Qualification - System Data Automati 665,143.85 7092999 12 Servers - NEW AMAG Servers 660,433.93 7091300 VCOC - B1 Expansion_I 646,393.91 74017111 Wireless Enhancements - Feather 640,961.38 70036204 CCSF � (CAP) 636,312.92 7092051 77 Beale GO-8th,27th Flrs Refresh_I (IO) 599,841.31 70029805 Black Butte to Red Rock Mountain PTP Upg 593,335.97 7083653 Radio Reliability - Carmel Valley 582,191.06 70036326 Cloud Security Automation (CAP) 581,858.46 70030780 Motherlode - VoIP 579,821.51 7092245 Colma SC - Security Program - Area 1 575,810.04 70036283 IO - 2018 Switch Lifecycle 572,359.54 70034662 Lights Out Management 562,205.22 70033129 NEM 2.0 Customer Bill Presentment Cap 557,636.95 70032183 D110 (Morro Bay - Tassajara) 532,861.08 70036847 IGP - FAN - South 529,058.63 70031025 DS0 Migration Project Phase II (Testing) 521,869.38 70036480 Access Request and Review Capital 520,688.97 70033771 OP: AMSM - Enterprise Network Mgmt Syst 515,426.22 70037131 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP HG 512,918.91 70037127 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP TO 512,918.84 70037128 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP ED 512,918.84 70037129 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP GD 512,918.84 70037130 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP IT 512,918.84 70036043 IO - Cloud Enablement - Networking 501,506.12 70027586 Radio Reliability - Lime Mt 491,585.38 70031243 Inspect - Canal (HG) - CAP 487,702.27 70036600 IO-2018 ODN Cap Incrs Reliab Imprv (TO) 460,330.68 70033147 Pole Loading Tool Upgrade with Industry 456,506.12 70036226 Communication-SCADA 445,147.71 70036381 FIP - Marysville Warehouse 439,697.04 7089807 Bay Area Program - GO_I (CAR 1C) 439,443.69 70037921 IO - Total Cost of Ownership (Cap) 434,376.68 70037088 IGP - SCADA -ODN Upgrades 434,277.95 7093845 Bay Area Optimization Pgm-East Bay PH 1 424,800.07 74019740 RPM Wave 2 CAP 421,712.90 7093305 Spacefinder Program 403,672.95 70033562 Hughes Satellite Terminal Replacement 380,864.70 70037082 IGP - SCADA - Digi Upgrades 374,305.25 7094205 ADMS SI Planning 374,147.97 70032800 Battle Creek - VSAT Emergency Phones 372,005.87 70034622 Hinkley Comp Station Ntwrk Remediation 363,299.12 70032184 D115 (Davis Peak-Morro Bay) 359,609.45 7092046 SFGO - Conference Rooms Refresh_I (IO) 358,522.75 74017108 Kings-Crane Network Extension 358,450.03 70036741 IO - WIFI Everywhere-Field Ph 2 - W3 352,036.26 70037326 CWSP: Vegetation Mgmt Data Enablement C 342,737.28 70034962 Lvl 3 Lat Bld-Brlngm Sub/San Crls/Mv Sub 335,731.47 70037405 CWSP: Maps+ for Emergency Mgmt (ED) CAP 331,359.22 70037407 CWSP: Maps+ for Emergency Mgmt (HG) CAP 323,455.04 70037408 CWSP: Maps+ for Emergency Mgmt (GT&S) C 323,455.04 70037409 CWSP: Maps+ for Emergency Mgmt (TO) CAP 323,455.04 70037406 CWSP: Maps+ for Emergency Mgmt (GD) CAP 323,454.88 7091752 Auburn Garage - Two Lifts 319,250.84 70036795 IO - CF - FFIOC 318,066.50 70029581 EMS SMP Server Replacement 312,970.90 70036327 Advanced Security Svcs for O365 (CAP) 307,293.72 70032303 Bentley-SAP Integration CAP ED 306,913.00 70036041 IO-AMSM-SCCM ODN-Windows 10/Server 2016 306,737.34 70037482 CWSP: Bill Ops Atmation for Mjr Evnt - C 297,446.35 7092291 System - SC Security Program - Area 5 295,938.93 70033696 Cimplicity to PI for Compressor Stations 295,410.69 70031242 Linear Inspection (Prev ET) - CAP 293,667.87 70032182 D111 (Tassajara to EOF) 292,608.05 70037084 IGP - SCADA - Masters 290,427.52 70036380 IO - SCADA Power Reliability: Table Mtn. 288,943.83 7093000 245 Market Lobby Turnstiles 288,327.96 7093307 Livermore - Transformer Lab Building 286,055.83 7092309 Facility Asset Upkeep - Area 5 285,730.48 70037126 EPM - CHANGE CNTRL & AUTH/RE-AUTH CAP GT 284,954.95 74017115 DCPP Remediate Vulnerable Operating Sys 280,884.19 7093807 DREBA2017-R24 CLICKTHRU-P3-IT-Sol3-CAP 279,807.61 7091750 30k Drive on Hoist 278,640.80 70033563 IO - SCADA Power Reliability: TES Facili 277,263.04 70032181 D112 (EOF to Black Butte) 275,880.65 74017103 Drum - VoIP 273,712.82 70036540 IO-ZAYO-Newark to Sunol Y Rstr(ADSS Ph1) 273,010.68 70036025 Data Sec Governance Access Remediation 268,225.08 7091108 Materials & Spoils Bay Covers 267,678.52 7093545 ESP Improvement Project 265,576.48 70036213 IO - Digital Mobile Radio (DMR) Backend 264,429.26 7092805 Fresno Thorne Avenue - Develop OU-3 257,746.81 70031540 Hydro HVP Program 257,210.99 74017114 PGEN Station Tech Upgrade Program 254,510.16 70036208 IO -Develop Fiber Mux Platform to Replac 253,436.07 ------------- Subtotal - Projects with more than $250,000 in actual costs in CWIP, excluding Research, Development, & Demonstration jobs $ 478,291,300.57 Aggregate total of projects with less than $250,000 in actual costs in Construction Work in Progress, including credits representing preliminary billings. $ 9,988,176.00 -------------- TOTAL CWIP - COMMON $ 488,279,477.56


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
  1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line No.
Description of Item(s)
(a)
Balance at End of Quarter 1
(b)
Balance at End of Quarter 2
(c)
Balance at End of Quarter 3
(d)
Balance at End of Year
(e)
1 Energy
2 Net Purchases (Account 555)
91,388,877
65,382,174
43,094,470
261,565,491
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
8,123,190
14,078,638
195,984,093
344,978,739
4 Transmission Rights
5 Ancillary Services
2,358,942
2,043,552
6,946,921
12,794,035
6 Other Items (list separately)
7
Grid Management Charges
10,595,990
11,254,478
13,252,982
45,707,324
8
FERC Fees
1,047,892
988,383
1,172,575
4,020,007
9
ISO Congestion
10
Unaccounted for Energy
5,331,131
7,649,507
1,430,485
5,984,445
11
Congestion Revenue Rights-Hedge
6,984,607
4,282,099
6,499,743
12,298,389
12
Congestion Revenue Rights-Auction
623,720
418,311
4,716,222
6,731,613
13
Convergence Bidding
28,243
166,886
195,129
14
Other ISO-related charges:
15
Minimum Load
16
Neutrality
150,330
22,028
286,069
122,929
17
Voltage Support
18
Other
3,638,725
3,786,149
8,625,911
20,246,014
19
Cost Recovery
1,012,384
1,052,640
5,084,223
2,004,244
20
Inter Day Ahead SC Trade
21
Inter Real Time SC Trade
22
Interest
209,893
216,943
103,343
691,342
23
Capacity - Other
388,198
4,332,938
3,583,688
10,656,463
24
DA IFM Credit Allocation
8,073,047
8,444,673
21,072,175
47,945,298
25
RT Offset/Allocation
5,618,045
5,215,103
19,989,516
31,748,255
26
Net Purchases for Energy Storage
58,374
153,238
22,917
220,207
46 TOTAL
104,831,614
53,242,424
138,618,809
42,272,496


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
  1. On line 1 columns (b), (c), (d), and (e) report the amount of ancillary services purchased and sold during the year.
  2. On line 2 columns (b), (c), (d), and (e) report the amount of reactive supply and voltage control services purchased and sold during the year.
  3. On line 3 columns (b), (c), (d), and (e) report the amount of regulation and frequency response services purchased and sold during the year.
  4. On line 4 columns (b), (c), (d), and (e) report the amount of energy imbalance services purchased and sold during the year.
  5. On lines 5 and 6, columns (b), (c), (d), and (e) report the amount of operating reserve spinning and supplement services purchased and sold during the period.
  6. On line 7 columns (b), (c), (d), and (e) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Line No.
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of Measure
(c)
Dollar
(d)
Number of Units
(e)
Unit of Measure
(f)
Dollars
(g)
1
Scheduling, System Control and Dispatch
N/A
2
Reactive Supply and Voltage
kW-Month
3
Regulation and Frequency Response
kW-Month
4
Energy Imbalance
kWh
5
Operating Reserve - Spinning
kW-Month
6
Operating Reserve - Supplement
kW-Month
7
Other
Various
1,878,331
Various
14,672,366
8
Total (Lines 1 thru 7)
1,878,331
14,672,366


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: AncillaryServicesPurchasedNumberOfUnits

All Ancillary Services (AS) purchases and sales are covered under the FERC approved ISO Tariff. Definitions of AS under Order No. 888 and the ISO Tariff are not consistent with one another. In order to avoid confusion as to meanings and terminologies, ISO AS amounts are not included on these lines but are reported on Line 7.

(b) Concept: AncillaryServicesPurchasedNumberOfUnits

 

This line includes Ancillary Services as follows:

 

 

 

 

 

 

 

 

 

 

 

 

 

AS under grandfathered existing contracts

 

 

 

 

 

Regulation Service Charge

 

-

-

-

 

Flat Charge

0

 

 

 

 

 

 

 

 

ISO related AS activities

 

 

 

 

 

 

 

Retail/BART ISO Purchases and Sales and

 

 

 

 

 

Existing Transmission Contracts (ETC) (a)

-

Various

1,878,331

-

Various

14,672,366

 

 

 

 

 

 

 

 

Total

 

 

 

1,878,331

 

 

14,672,366

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a) This comprised of various billing determinants which the ISO uses to calculate the amounts of AS sold or purchased.

This item also includes ISO AS purchases/sales by the Utility in its role as Scheduling Coordinator for ETCs.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
  1. Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Firm Network Service for Self
(e)
Firm Network Service for Others
(f)
Long-Term Firm Point-to-point Reservations
(g)
Other Long-Term Firm Service
(h)
Short-Term Firm Point-to-point Reservation
(i)
Other Service
(j)
NAME OF SYSTEM: PACFIC GAS AND ELECTRIC COMPANY-0
1
January
2
February
3
March
4
Total for Quarter 1
5
April
6
May
7
June
8
Total for Quarter 2
9
July
10
August
11
September
12
Total for Quarter 3
13
October
14
November
15
December
16
Total for Quarter 4
17
Total
NAME OF SYSTEM: PACIFIC GAS AND ELECTRIC COMPANY-0
1
January
13,520
8
1,900
8,128
50
5,342
2
February
14,095
20
1,900
8,911
5,184
3
March
13,009
5
2,000
7,762
5,247
4
Total for Quarter 1
24,801
50
15,773
5
April
13,395
23
2,100
7,404
60
5,931
6
May
16,268
29
1,900
9,717
100
6,451
7
June
18,048
23
1,900
10,439
100
7,509
8
Total for Quarter 2
27,560
260
19,891
9
July
18,973
25
1,900
10,876
75
8,022
10
August
18,633
9
1,900
10,338
75
8,220
11
September
16,455
7
1,800
8,826
100
7,529
12
Total for Quarter 3
30,040
250
23,771
13
October
14,354
2
2,000
6,778
100
7,476
14
November
13,142
14
1,900
6,192
100
6,850
15
December
13,770
4
1,900
5,165
100
8,505
16
Total for Quarter 4
18,135
300
22,831
17
Total
100,536
860
82,266


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Monthly ISO/RTO Transmission System Peak Load
  1. Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system.
  2. Report on Column (b) by month the transmission system's peak load.
  3. Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
  4. Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f).
  5. Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).
Line No.
Month
(a)
Monthly Peak MW - Total
(b)
Day of Monthly Peak
(c)
Hour of Monthly Peak
(d)
Import into ISO/RTO
(e)
Exports from ISO/RTO
(f)
Through and Out Service
(g)
Network Service Usage
(h)
Point-to-Point Service Usage
(i)
Total Usage
(j)
NAME OF SYSTEM: Enter System
1
January
2
February
3
March
4
Total for Quarter 1
5
April
6
May
7
June
8
Total for Quarter 2
9
July
10
August
11
September
12
Total for Quarter 3
13
October
14
November
15
December
16
Total for Quarter 4
17
Total Year to Date/Year


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-16
Year/Period of Report

End of:
2018
/
Q4
ELECTRIC ENERGY ACCOUNT

Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

Line No. Item
(a)
MegaWatt Hours
(b)
Line No. Item
(a)
MegaWatt Hours
(b)
1
SOURCES OF ENERGY
21
DISPOSITION OF ENERGY
2
Generation (Excluding Station Use):
22
Sales to Ultimate Consumers (Including Interdepartmental Sales)
(a)(b)(c)
80,066,264
3
Steam
(d)(e)
5,931,611
23
Requirements Sales for Resale (See instruction 4, page 311.)
(f)
10,790,942
4
Nuclear
(g)
18,265,519
24
Non-Requirements Sales for Resale (See instruction 4, page 311.)
5
Hydro-Conventional
(h)
7,826,709
25
Energy Furnished Without Charge
6
Hydro-Pumped Storage
(i)
784,053
26
Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7
Other
(k)(l)
710,920
27
Total Energy Losses
3,331,574
8
Less Energy for Pumping
(m)
1,212,365
27.1
Total Energy Stored
9
Net Generation (Enter Total of lines 3 through 8)
(n)
32,306,447
28
TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES
63,638,989
10
Purchases (other than for Energy Storage)
(o)(p)
31,325,610
10.1
Purchases for Energy Storage
11
Power Exchanges:
12
Received
13
Delivered
14
Net Exchanges (Line 12 minus line 13)
15
Transmission For Other (Wheeling)
16
Received
(q)
366,570
17
Delivered
(r)
359,638
18
Net Transmission for Other (Line 16 minus line 17)
(s)
6,932
19
Transmission By Others Losses
20
TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)
(t)
63,638,989


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

2019-04-16
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MegawattHoursSoldSalesToUltimateConsumers

This includes MWH sales for DWR and DA as discussed in the footnote to Line 10, column b.

(b) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 49516473
(c) Concept: MegawattHoursSoldSalesToUltimateConsumers
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 22, Column: b, Value: 0
(d) Concept: SteamGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 3, Column: b, Value: 0
(e) Concept: SteamGeneration

This line includes combined cycle plants only. It does not include internal combustion reciprocating engines, which are included on Line 7.

(f) Concept: MegawattHoursSoldRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 23, Column: b, Value: 0
(g) Concept: NuclearGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 4, Column: b, Value: 0
(h) Concept: HydroConventionalGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 5, Column: b, Value: 0
(i) Concept: HydroPumpedStorageGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 6, Column: b, Value: 0
(j) Concept: InternalUseEnergy

Data for energy used by the Electric department is not separately available but is included on Line 22.

(k) Concept: OtherEnergyGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 7, Column: b, Value: 0
(l) Concept: OtherEnergyGeneration

This line includes internal combustion reciprocating engines, photo voltaic and Fuel Cells. This includes photo voltaic generation of 310,219 MWh.

(m) Concept: PumpingEnergy
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 8, Column: b, Value: 0
(n) Concept: NetEnergyGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 9, Column: b, Value: 0
(o) Concept: MegawattHoursPurchasedOtherThanStorage

For purposes only of accounting for the total energy that went through the Utility's electric system, the MWH for Direct Access ("DA") is 30,549,791 MWH. It should be noted that DA and DWR megawatts are not Utility purchases and were reported here only because page 401 of the Form 1 does not have any other available line where DA and DWR deliveries can be shown more appropriately.

 

The Utility acts as a pass-through entity for electricity purchased by the DWR that is sold to the Utility's customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from electricity revenue amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers, priced at the related CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility's electricity revenues in its Statement of Income.

(p) Concept: MegawattHoursPurchasedOtherThanStorage
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 10, Column: b, Value: 0
(q) Concept: ElectricPowerWheelingEnergyReceived
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 16, Column: b, Value: 0
(r) Concept: ElectricPowerWheelingEnergyDelivered
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 17, Column: b, Value: 0
(s) Concept: NetTransmissionEnergyForOthersElectricPowerWheeling
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 18, Column: b, Value: 0
(t) Concept: SourcesOfEnergy
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 20, Column: b, Value: 0

Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
MONTHLY PEAKS AND OUTPUT
  1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system.
  2. Report in column (b) by month the system’s output in Megawatt hours for each month.
  3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
  4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
  5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
Line No.
MonthAxis
Month
(a)
EnergyActivity
Total Monthly Energy
(b)
NonRequiredSalesForResaleEnergy
Monthly Non-Requirement Sales for Resale & Associated Losses
(c)
MonthlyPeakLoad
Monthly Peak - Megawatts
(d)
DayOfMonthlyPeak
Monthly Peak - Day of Month
(e)
HourOfMonthlyPeak
Monthly Peak - Hour
(f)
NAME OF SYSTEM: PACFIC GAS AND ELECTRIC COMPANY
29
January
5,029,823
11,901
8
1,900
30
February
4,581,182
12,624
20
1,900
31
March
4,859,705
11,406
5
2,000
32
April
4,665,634
12,046
23
2,100
33
May
5,154,051
14,705
29
1,900
34
June
5,677,493
16,428
23
1,900
35
July
6,634,933
17,263
25
1,900
36
August
6,251,443
16,770
9
1,900
37
September
5,383,907
14,729
7
1,800
38
October
5,305,835
12,813
2
2,000
39
November
4,841,750
11,642
14
1,900
40
December
5,253,233
12,315
4
1,900
41
Total


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Steam Electric Generating Plant Statistics

1. Report data for plant in Service only.
2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants.
3. Indicate by a footnote any plant leased or operated as a joint facility.
4. If net peak demand for 60 minutes is not available, give data which is available, specifying period.
5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant.
6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct.
7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20.
8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses.
10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants.
11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant.
12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

Line No.
Item
(a)
Plant Name:
Colusa Gen Station
Plant Name:
Diablo Canyon 1& 2
Plant Name:
Gateway Gen Station
Plant Name:
Humboldt Gen Station
1
PlantKind
Kind of Plant (Internal Comb, Gas Turb, Nuclear)
Combined Cycle
Nuclear
Combined Cycle
Internal Comb Recip
2
PlantConstructionType
Type of Constr (Conventional, Outdoor, Boiler, etc)
Outdoor
Conventional
Outdoor
Indoor
3
YearPlantOriginallyConstructed
Year Originally Constructed
2010
1968
2009
2010
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
2010
1986
2009
2011
5
InstalledCapacityOfPlant
Total Installed Cap (Max Gen Name Plate Ratings-MW)
711.45
2,323
619.65
162.7
6
NetPeakDemandOnPlant
Net Peak Demand on Plant - MW (60 minutes)
657
2,240
580
163
7
PlantHoursConnectedToLoad
Plant Hours Connected to Load
6,088
8,760
6,735
8,643
8
NetContinuousPlantCapability
Net Continuous Plant Capability (Megawatts)
9
NetContinuousPlantCapabilityNotLimitedByCondenserWater
When Not Limited by Condenser Water
2,240
10
NetContinuousPlantCapabilityLimitedByCondenserWater
When Limited by Condenser Water
2,240
11
PlantAverageNumberOfEmployees
Average Number of Employees
22
1,303
22
19
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - KWh
2,991,759,812
18,265,519,000
2,939,850,866
384,780,571
13
CostOfLandAndLandRightsSteamProduction
Cost of Plant: Land and Land Rights
7,889,274
22,726,560
5,040,000
161,399
14
CostOfStructuresAndImprovementsSteamProduction
Structures and Improvements
115,958,181
1,089,216,494
72,443,812
67,447,178
15
CostOfEquipmentSteamProduction
Equipment Costs
544,344,962
6,783,305,893
383,958,736
152,579,352
16
AssetRetirementCostsSteamProduction
Asset Retirement Costs
3,912,558
2,701,010,462
3,004,029
1,925,852
17
CostOfPlant
Total cost (total 13 thru 20)
672,104,975
10,596,259,409
464,446,577
222,113,781
18
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 17/5) Including
944.6974
4,561.4548
749.5305
1,365.1738
19
OperationSupervisionAndEngineeringExpense
Production Expenses: Oper, Supv, & Engr
257,077
4,025,966
257,077
78,872
20
FuelSteamPowerGeneration
Fuel
85,252,370
129,114,087
86,205,401
14,613,788
21
CoolantsAndWater
Coolants and Water (Nuclear Plants Only)
37,292,499
22
SteamExpensesSteamPowerGeneration
Steam Expenses
38,815,499
16,174
23
SteamFromOtherSources
Steam From Other Sources
24
SteamTransferredCredit
Steam Transferred (Cr)
25
ElectricExpensesSteamPowerGeneration
Electric Expenses
3,355,754
1,867,685
3,753,644
3,492,951
26
MiscellaneousSteamPowerExpenses
Misc Steam (or Nuclear) Power Expenses
687,396
334,859,486
896,002
989,204
27
RentsSteamPowerGeneration
Rents
28
Allowances
Allowances
16,636,516
16,631,614
2,384,413
29
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
Maintenance Supervision and Engineering
70,112
2,782,594
70,112
21,510
30
MaintenanceOfStructuresSteamPowerGeneration
Maintenance of Structures
1,903,977
3,442,055
59,850
204,863
31
MaintenanceOfBoilerPlantSteamPowerGeneration
Maintenance of Boiler (or reactor) Plant
700,898
26,816,759
703,572
73,824
32
MaintenanceOfElectricPlantSteamPowerGeneration
Maintenance of Electric Plant
2,950,795
36,172,375
3,627,718
5,609,397
33
MaintenanceOfMiscellaneousSteamPlant
Maintenance of Misc Steam (or Nuclear) Plant
3,033,692
83,619,837
1,282,815
34
PowerProductionExpensesSteamPower
Total Production Expenses
114,848,587
531,569,168
113,503,979
27,468,822
35
ExpensesPerNetKilowattHour
Expenses per Net KWh
0.0384
0.0291
0.0386
0.0714
35
FuelKindAxis
Plant Name
Colusa Gen Station
Diablo Canyon 1& 2
Gateway Gen Station
Humboldt Gen Station
Humboldt Gen Station
36
FuelKind
Fuel Kind
Gas
Nuclear
Gas
Gas
Oil
37
FuelUnit
Fuel Unit
Mcf
MWD
Mcf
Mcf
Bbl
38
QuantityOfFuelBurned
Quantity (Units) of Fuel Burned
20,823,676
2,303,440
20,357,260
3,225,039
2,734
39
FuelBurnedAverageHeatContent
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
1,039,167
1,041,167
1,040,917
5,795,804
40
AverageCostOfFuelPerUnitAsDelivered
Avg Cost of Fuel/unit, as Delvd f.o.b. during year
4.32
4.22
4.15
100.63
41
AverageCostOfFuelPerUnitBurned
Average Cost of Fuel per Unit Burned
4.59
55.847
4.49
5.48
101.02
42
AverageCostOfFuelBurnedPerMillionBritishThermalUnit
Average Cost of Fuel Burned per Million BTU
4.42
0.682
4.31
5.27
17.43
43
AverageCostOfFuelBurnedPerKilowattHourNetGeneration
Average Cost of Fuel Burned per KWh Net Gen
0.03
0.007
0.03
0.05
0.14
44
AverageBritishThermalUnitPerKilowattHourNetGeneration
Average BTU per KWh Net Generation
7,233
10,327.208
7,210
8,885
8,089


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Hydroelectric Generating Plant Statistics
  1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number.
  3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
  4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Line No.
Item
(a)
FERC Licensed Project No.
1354
Plant Name:
A.G. WISHON
FERC Licensed Project No.
175
Plant Name:
BALCH NO. 1
FERC Licensed Project No.
175
Plant Name:
BALCH NO. 2
FERC Licensed Project No.
2105
Plant Name:
BELDEN
FERC Licensed Project No.
619
Plant Name:
BUCKS CREEK
FERC Licensed Project No.
2105
Plant Name:
BUTT VALLEY
FERC Licensed Project No.
2105
Plant Name:
CARIBOU NO. 1
FERC Licensed Project No.
2105
Plant Name:
CARIBOU NO. 2
FERC Licensed Project No.
1121
Plant Name:
COLEMAN
FERC Licensed Project No.
1962
Plant Name:
CRESTA
FERC Licensed Project No.
803
Plant Name:
DE SABLA
FERC Licensed Project No.
2310
Plant Name:
DRUM NO. 1
FERC Licensed Project No.
2310
Plant Name:
DRUM NO. 2
FERC Licensed Project No.
2310
Plant Name:
DUTCH FLAT
FERC Licensed Project No.
137
Plant Name:
ELECTRA
FERC Licensed Project No.
1988
Plant Name:
HAAS
FERC Licensed Project No.
2130
Plant Name:
HALSEY
FERC Licensed Project No.
2661
Plant Name:
HAT CREEK NO. 1
FERC Licensed Project No.
2661
Plant Name:
HAT CREEK NO. 2
FERC Licensed Project No.
2106
Plant Name:
JAMES B. BLACK
FERC Licensed Project No.
96
Plant Name:
KERCKHOFF NO. 1
FERC Licensed Project No.
96
Plant Name:
KERCKHOFF NO. 2
FERC Licensed Project No.
1988
Plant Name:
KINGS RIVER
FERC Licensed Project No.
1403
Plant Name:
NARROWS
FERC Licensed Project No.
2310
Plant Name:
NEWCASTLE
FERC Licensed Project No.
233
Plant Name:
PIT NO. 3
FERC Licensed Project No.
233
Plant Name:
PIT NO. 4
FERC Licensed Project No.
233
Plant Name:
PIT NO. 5
FERC Licensed Project No.
2106
Plant Name:
PIT NO. 6
FERC Licensed Project No.
2106
Plant Name:
PIT NO. 7
FERC Licensed Project No.
2687
Plant Name:
PIT NO.1
FERC Licensed Project No.
2107
Plant Name:
POE
FERC Licensed Project No.
1962
Plant Name:
ROCK CREEK
FERC Licensed Project No.
137
Plant Name:
SALT SPRINGS
FERC Licensed Project No.
2130
Plant Name:
STANISLAUS
FERC Licensed Project No.
137
Plant Name:
TIGER CREEK
FERC Licensed Project No.
137
Plant Name:
WEST POINT
FERC Licensed Project No.
2310
Plant Name:
WISE NO. 1
1
PlantKind
Kind of Plant (Run-of-River or Storage)
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
R of R/Storage
2
PlantConstructionType
Plant Construction type (Conventional or Outdoor)
Conventional
Conventional
Outdoor
Outdoor
Conventional
Outdoor
Conventional
Outdoor
Conventional
Conventional
Outdoor
Conventional
Outdoor
Conventional
Conventional
Conventional
Conventional
Conventional
Conventional
Outdoor
Conventional
Underground
Semi-Outdoor
Conventional
Conventional
Conventional
Conventional
Conventional
Outdoor
Outdoor
Conventional
Outdoor
Conventional
Conventional
Outdoor
Conventional
Conventional
Conventional
3
YearPlantOriginallyConstructed
Year Originally Constructed
1910
1927
1958
1969
1928
1958
1921
1958
1979
1949
1963
1913
1965
1943
1948
1958
1916
1921
1921
1965
1920
1983
1962
1942
1986
1925
1955
1944
1965
1965
1922
1958
1950
1931
1963
1931
1948
1917
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
1910
1927
1958
1969
1928
1958
1924
1958
1979
1950
1963
1928
1965
1943
1948
1958
1916
1921
1921
1966
1920
1983
1962
1942
1986
1925
1955
1944
1965
1965
1922
1958
1950
1953
1963
1931
1948
1917
5
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
12.8
31
97.2
117.9
66
40
73.85
117.9
12.15
73.8
18.45
49.2
53.1
22
102.5
135
13.6
10
10
168.66
22.72
139.5
48.6
10.2
12.7
80.19
103.5
141.84
79.2
109.8
69.3
142.83
125.37
42.03
81.9
52.28
13.6
13.6
6
NetPeakDemandOnPlant
Net Peak Demand on Plant-Megawatts (60 minutes)
20
34
105
125
65
41
75
120
13
70
19
54
50
22
98
144
11
9
9
172
25
155
52
12
12
70
95
160
80
112
61
120
126
44
91
58
15
14
7
PlantHoursConnectedToLoad
Plant Hours Connect to Load
6,585
7,972
8,727
5,882
8,410
4,736
6,717
7,976
8,445
7,073
7,690
3,181
8,147
6,876
5,693
7,610
7,123
8,377
8,601
8,709
5,775
7,410
2,314
3,102
6,570
8,758
8,596
8,256
8,614
7,967
7,119
7,564
7,965
7,644
7,942
7,939
8
NetPlantCapabilityAbstract
Net Plant Capability (in megawatts)
9
NetPlantCapabilityUnderMostFavorableOperatingConditions
(a) Under Most Favorable Oper Conditions
20
34
105
125
65
41
75
120
13
70
19
54
50
22
98
144
11
9
9
172
25
155
52
12
12
70
95
160
80
112
61
120
119
44
91
58
15
14
10
NetPlantCapabilityUnderMostAdverseOperatingConditions
(b) Under the Most Adverse Oper Conditions
12
34
104
125
53
38
74
119
5
72
19
54
49
23
98
138
11
4
9
172
151
52
12
70
95
160
80
112
61
120
119
34
91
58
13
14
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - Kwh
25,652,329
82,111,021
401,299,232
235,266,815
128,911,667
57,118,200
110,532,743
360,239,676
45,302,645
187,135,206
59,656,524
83,913,780
230,525,842
65,434,392
318,290,353
360,886,120
360,886,120
36,812,536
31,284,521
542,644,584
327,205,316
132,080,338
22,728,278
10,786,767
257,432,979
400,071,744
612,975,367
267,438,940
357,690,402
227,075,869
447,646,495
322,644,207
125,695,957
333,256,359
227,420,171
69,020,934
65,589,885
13
CostOfPlantAbstract
Cost of Plant
14
CostOfLandAndLandRightsHydroelectricProduction
Land and Land Rights
976,875
8,165
2,630
640,218
810,543
398,183
330,012
384,372
183,058
1,364,764
146,825
1,571,285
441,826
785,641
735,286
30,588
30,588
1,047,218
733,666
568,139
6,969
584,910
15,682
274,399
2,066,271
3,791,145
312,988
687,742
387,337
323,678
2,307,798
821,303
1,777,666
221,450
428,932
2,572,625
150,912
823,681
15
CostOfStructuresAndImprovementsHydroelectricProduction
Structures and Improvements
1,528,365
854,160
5,192,179
11,727,773
1,474,672
3,151,323
6,709,663
11,189,102
1,704,073
5,714,160
3,122,920
5,541,698
1,142,045
2,115,430
2,610,434
11,737,499
11,737,499
2,985,501
759,980
766,934
1,651,408
39,045,952
5,271,515
1,173,893
6,583,663
9,206,074
4,300,149
21,149,838
6,941,414
6,856,399
2,253,094
4,046,851
21,460,445
2,486,698
6,477,282
8,123,675
1,039,104
4,096,375
16
CostOfReservoirsDamsAndWaterwaysHydroelectricProduction
Reservoirs, Dams, and Waterways
51,024,316
9,448,057
7,126,485
58,173,965
21,114,877
36,503,597
28,499,090
36,168,942
23,741,590
23,843,112
41,913,456
39,678,065
11,721,651
19,247,540
27,559,897
29,603,124
29,603,124
28,366,638
2,775,286
66,249,996
3,325,126
90,039,658
20,171,097
1,220,149
47,616,591
68,460,657
41,021,512
46,537,842
36,377,850
31,436,620
13,046,575
59,968,899
47,873,280
33,803,923
36,736,275
54,661,888
5,959,695
17,299,241
17
EquipmentCostsHydroelectricProduction
Equipment Costs
6,364,363
9,802,804
38,968,422
63,607,879
22,420,669
15,512,934
29,651,344
34,736,018
13,332,433
11,848,381
6,170,443
23,339,876
8,187,291
15,746,022
24,856,303
41,123,297
41,123,297
10,025,561
2,822,191
18,207,990
6,167,177
52,285,342
13,981,486
7,129,685
8,338,520
29,942,674
38,028,307
90,880,556
13,377,803
11,787,529
38,723,193
38,904,520
106,581,651
13,510,239
20,380,012
26,815,105
7,585,844
10,714,439
18
CostOfRoadsRailroadsAndBridgesHydroelectricProduction
Roads, Railroads, and Bridges
29,468
1,327,037
1,739,338
479,445
3,068,244
2,679,316
5,360,063
17,594
1,870,299
135,388
2,441,056
1,410,081
479,135
394,378
1,407,837
797,929
797,929
267,475
1,171,981
2,073,884
6,186
7,536,660
354,839
506,708
3,056,166
7,126,541
3,913,417
9,456,338
687,395
406,204
1,448,928
1,626,548
354,708
1,528,393
1,142,259
7,729,944
285,168
212,689
19
AssetRetirementCostsHydroelectricProduction
Asset Retirement Costs
20
CostOfPlant
Total cost (total 13 thru 20)
59,923,387
21,440,223
53,029,054
134,629,280
48,889,005
58,245,353
70,550,172
82,496,028
40,831,453
42,905,805
53,794,700
71,541,005
21,971,948
38,289,011
57,169,757
83,292,437
83,292,437
42,692,393
8,263,104
87,866,943
11,156,866
189,492,522
39,794,619
10,304,834
67,661,211
118,527,091
87,576,373
168,712,316
57,771,799
50,810,430
57,779,588
105,368,121
178,047,750
51,550,703
65,164,760
99,903,237
15,020,723
33,146,425
21
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 20 / 5)
4,681.5146
691.6201
545.5664
1,141.8938
740.7425
1,456.1338
955.3172
699.7119
3,360.6134
581.3795
2,915.7019
1,454.0855
413.7843
1,740.4096
557.7537
616.981
6,124.4439
4,269.2393
826.3104
520.9708
491.0592
1,358.3693
818.8193
1,010.2778
5,327.6544
1,478.0782
846.1485
1,189.4551
729.4419
462.7544
833.7603
737.717
1,420.1783
1,226.5216
795.6625
1,910.9265
1,104.4649
2,437.2371
22
ProductionExpensesAbstract
Production Expenses
23
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
24
WaterForPower
Water for Power
226,010
3,425
9,227
109,846
123,794
39,605
68,036
105,665
816
5,115
514
40,807
37,531
17,510
133,967
12,341
9,502
29,023
1,430
5,622
4,862
275,357
9,866
47,633
55,627
29,023
29,023
102,586
5,115
5,115
6,768
443,972
7,791
2,466
11,686
25
HydraulicExpenses
Hydraulic Expenses
10,255
31,671
15,060
9,739
16,203
10,626
14,616
915
15,680
26,225
177,263
174,879
188,829
27,411
43,435
4,155
541
541
24,631
15,685
750
18,141
19,732
23,867
18,777
20,813
17,569
17,821
15,149
40,675
99,843
20,754
8,514
753
26
ElectricExpensesHydraulicPowerGeneration
Electric Expenses
141,132
141,901
222,402
325,229
152,309
331,157
1,216,193
311,043
408,911
150,542
710,981
412,909
276,612
373,186
1,188,342
556,293
80,343
236,960
222,193
295,071
120,285
294,966
148,958
60,759
26,667
611,456
347,785
491,392
239,460
260,382
280,102
160,193
1,305,645
1,220,312
2,159,136
805,139
265,700
544,347
27
MiscellaneousHydraulicPowerGenerationExpenses
Misc Hydraulic Power Generation Expenses
1,101,147
61,751
189,223
23,493
380,933
568
993
1,557
178,071
268,200
6,414,625
7,945
7,308
3,416
87,461
26,448
1,859
1,060,857
1,060,857
262,179
250,398
1,503,660
5,276
162,775
1,929
193,482
208,709
242,382
214,354
231,740
890,136
441,670
503,409
145,550
455,979
57,930
25,814
2,283
28
RentsHydraulicPowerGeneration
Rents
4,223
28,076
86,622
15,455
21,222
5,090
9,285
14,838
9
20,367
37,840
52,689
48,459
22,609
358
30,946
12,269
2,626
2,626
11,574
64,673
394,577
11,194
12,739
136
136
136
11,574
11,574
9,078
36,660
191
98,596
220
70
15,089
29
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresHydraulicPowerGeneration
Maintenance of Structures
37,196
46,779
144,781
39,202
104,521
19,463
173,963
37,777
126,828
145,717
129,091
12,081
10,751
7,976
264,892
293,460
60,478
6,708
3,781
10,544
48,693
16,962
68,975
5,163
5,090
2,452
6,532
1,913,381
3,117
8,835
2,189
139,354
214,260
188,819
1,323,933
244,804
53,419
8,319
31
MaintenanceOfReservoirsDamsAndWaterways
Maintenance of Reservoirs, Dams, and Waterways
15,931
76,354
217,457
164,300
155,089
256,689
162,686
81,701
891,380
910,723
671,745
66,665
57,047
54,137
501,819
248,746
286,018
24,517
45,520
25,025
10,878
90,326
93,735
12,731
216,058
25,981
30,753
1,837,724
1,650
67,350
187,003
141,098
1,166,484
7,890,183
551,243
607,423
161,253
250,741
32
MaintenanceOfElectricPlantHydraulicPowerGeneration
Maintenance of Electric Plant
144,810
107,740
238,068
219,749
79,078
220,079
515,227
197,617
209,817
407,226
742,172
123,476
65,920
62,417
517,527
859,834
89,897
83,446
50,291
213,236
48,543
519,602
144,568
151,270
114,850
781,487
324,107
996,140
151,601
577,602
210,328
613,095
360,826
359,088
523,463
394,602
243,258
76,288
33
MaintenanceOfMiscellaneousHydraulicPlant
Maintenance of Misc Hydraulic Plant
56
491,536
1,369,778
146,665
79,279
76,687
176,542
82,765
1,028,538
62,920
1,205,012
90,744
86,076
57,551
10,747
1,735,782
174,827
12,594
33,359
24,451
49,312
313,706
588,886
15,945
168,341
178,998
22,194
142,918
28,067
10,650
50,070
147,657
84,633
5,848
21,893
7,008
2,152
170,446
34
PowerProductionExpensesHydraulicPower
Total Production Expenses (total 23 thru 33)
1,670,505
967,817
2,509,229
1,058,999
1,105,964
965,541
2,333,551
847,579
2,845,285
1,986,490
9,938,205
984,579
764,583
787,631
2,732,524
3,807,285
719,348
1,428,249
1,419,168
895,734
594,212
3,139,421
1,082,139
684,750
555,540
1,859,766
1,015,575
2,140,106
697,623
1,217,969
1,739,983
1,675,081
3,692,181
9,857,434
5,678,058
2,145,671
762,646
1,079,952
35
ExpensesPerNetKilowattHour
Expenses per net KWh
0.0651
0.0118
0.0063
0.0045
0.0086
0.0169
0.0211
0.0024
0.0628
0.0106
0.1666
0.0117
0.0033
0.012
0.0086
0.0105
0.002
0.0388
0.0454
0.0017
0.0096
0.0082
0.0301
0.0515
0.0072
0.0025
0.0035
0.0026
0.0034
0.0077
0.0037
0.0114
0.0784
0.017
0.0094
0.011
0.0165


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PlantAverageNumberOfEmployees

Schedule Page: 406 Line No.: 11 Column: b

 

Certain FERC Licensed plants have a zero Line 11 (Average Number of Employees) on pages 406 and 407 due to remote operation and headquarters. Refer to the table below for further details for each plant with a zero in Line 11. Each of these plants is attended by roving or relief operators.

 

 

PLANT NAME:

REMOTELY OPERATED (Y/N):

REGIONAL OPERATING

CENTER:

NUMER OF OPERATORS:

OPERATIONS HEADQUARTERS:

NUMBER OF OPERATORS:

MAINTENANCE HEADQUARTERS:

NUMBER OF SUPPORT STAFF:

PIT NO. 1

Y

NA

NA

Pit 3 PH

8

Burney Service

39

PIT NO. 3

Y

 

 

Switching Center

 

Center

 

PIT NO. 4

Y

 

 

 

 

 

 

HAT CREEK NO. 1

N

 

 

 

 

 

 

HAT CREEK NO. 2

N

 

 

 

 

 

 

PIT NO. 5

Y

 

 

Pit 5 PH

7

 

 

PIT NO. 6

Y

 

 

Switching Center

 

 

 

PIT NO. 7

Y

 

 

 

 

 

 

JAMES B. BLACK

Y

 

 

 

 

 

 

COLEMAN

N

 

 

Manton

4

Manton

7

DE SABLA

N

 

 

Camp 1

5

Camp 1

6

BUTT VALLEY

Y

 

 

Caribou

8

Rogers Flat

37

CARIBOU NO. 1

Y

 

 

Switching Center

 

Service Center

 

CARIBOU NO. 2

Y

 

 

 

 

 

 

BELDEN

Y

 

 

 

 

 

 

ROCK CREEK

Y

 

 

Rock Creek

11

 

 

BUCKS CREEK

Y

 

 

Switching Center

 

 

 

CRESTA

Y

 

 

 

 

 

 

POE

Y

 

 

 

 

 

 

DRUM NO. 1

N

 

 

Drum

7

Auburn SC

25

DRUM NO. 2

Y

 

 

Switching Center

 

Service Center

 

DUTCH FLAT

Y

 

 

Alta Service Center

3

 

 

NARROWS

Y

 

 

Wise

11

Alta Service Center

10

HALSEY

Y

 

 

Switching Center

 

 

 

WISE NO. 1

N

 

 

 

 

 

 

NEWCASTLE

Y

 

 

 

 

 

 

SALT SPRINGS

N

 

 

Tiger Creek

10

Tiger Creek

12

TIGER CREEK

Y

 

 

Switching Center

 

Service Center

 

WEST POINT

Y

 

 

 

 

 

 

ELECTRA

Y

 

 

 

 

 

 

STANISLAUS

Y

 

 

Angels Camp Service Center

3

Angels Camp Service Center

10

HAAS

Y

Fresno

5

Balch Camp

8

Auberry

21

BALCH NO. 1

Y

Operating Center

 

 

Service Center

 

BALCH NO. 2

Y

 

 

 

 

 

 

KINGS RIVER

Y

 

 

 

 

 

 

KERCKHOFF NO. 1

Y

 

 

Auberry

11

 

 

KERCKHOFF NO. 2

Y

 

 

Service Center

 

 

 

A. G. WISHON

N

 

 

 

 

 

 

 


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
Pumped Storage Generating Plant Statistics
  1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings).
  2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number.
  3. If net peak demand for 60 minutes is not available, give the which is available, specifying period.
  4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant.
  5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
  6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes.
  7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.
Line No.
Item
(a)
FERC Licensed Project No.
2735
Plant Name:
HELMS PUMPED STORAGE
1
PlantConstructionType
Type of Plant Construction (Conventional or Outdoor)
Underground
2
YearPlantOriginallyConstructed
Year Originally Constructed
1984
3
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
1984
4
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
1,053
5
NetPeakDemandOnPlant
Net Peak Demaind on Plant-Megawatts (60 minutes)
1,050
6
PlantHoursConnectedToLoad
Plant Hours Connect to Load While Generating
2,811
7
NetContinuousPlantCapability
Net Plant Capability (in megawatts)
1,212
8
PlantAverageNumberOfEmployees
Average Number of Employees
20
9
NetGenerationExcludingPlantUse
Generation, Exclusive of Plant Use - Kwh
784,053,024
10
EnergyUsedForPumping
Energy Used for Pumping
1,212,364,607
11
NetOutputForLoad
Net Output for Load (line 9 - line 10) - Kwh
428,311,583
12
CostOfPlantAbstract
Cost of Plant
13
CostOfLandAndLandRightsPumpedStoragePlant
Land and Land Rights
751,302
14
CostOfStructuresAndImprovementsPumpedStoragePlant
Structures and Improvements
185,627,148
15
CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Reservoirs, Dams, and Waterways
450,931,223
16
CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant
Water Wheels, Turbines, and Generators
273,553,164
17
CostOfAccessoryElectricEquipmentPumpedStoragePlant
Accessory Electric Equipment
61,165,589
18
CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant
Miscellaneous Powerplant Equipment
25,902,828
19
CostOfRoadsRailroadsAndBridgesPumpedStoragePlant
Roads, Railroads, and Bridges
8,781,047
20
AssetRetirementCostsPumpedStoragePlant
Asset Retirement Costs
21
CostOfPlant
Total cost (total 13 thru 20)
1,006,712,301
22
CostPerKilowattOfInstalledCapacity
Cost per KW of installed cap (line 21 / 4)
956.0421
23
ProductionExpensesAbstract
Production Expenses
24
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
15,098
25
WaterForPower
Water for Power
343,813
26
PumpedStorageExpenses
Pumped Storage Expenses
13,239
27
ElectricExpensesPumpedStoragePlant
Electric Expenses
1,898,701
28
MiscellaneousPumpedStoragePowerGenerationExpenses
Misc Pumped Storage Power generation Expenses
2,101,242
29
RentsPumpedStoragePlant
Rents
44,587
30
MaintenanceSupervisionAndEngineeringPumpedStoragePlant
Maintenance Supervision and Engineering
1,028
31
MaintenanceOfStructuresPumpedStoragePlant
Maintenance of Structures
492,977
32
MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Maintenance of Reservoirs, Dams, and Waterways
523,237
33
MaintenanceOfElectricPlantPumpedStoragePlant
Maintenance of Electric Plant
3,139,730
34
MaintenanceOfMiscellaneousPumpedStoragePlant
Maintenance of Misc Pumped Storage Plant
1,174,188
35
PowerProductionExpenseBeforePumpingExpenses
Production Exp Before Pumping Exp (24 thru 34)
9,747,840
36
PumpingExpenses
Pumping Expenses
37
PowerProductionExpensesPumpedStoragePlant
Total Production Exp (total 35 and 36)
9,747,840
38
ExpensesPerNetKilowattHour
Expenses per KWh (line 37 / 9)
0.0124
39
ExpensesPerNetKilowattHourGenerationAndPumping
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
GENERATING PLANT STATISTICS (Small Plants)

1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.

3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.

Production Expenses
Line No.
PlantName
Name of Plant
(a)
YearPlantOriginallyConstructed
Year Orig. Const.
(b)
InstalledCapacityOfPlant
Installed Capacity Name Plate Rating (MW)
(c)
Net Peak Demand MW (60 min)
(d)
NetGenerationExcludingPlantUse
Net Generation Excluding Plant Use
(e)
Cost of Plant
(f)
PlantCostPerMw
Plant Cost (Incl Asset Retire. Costs) Per MW
(g)
OperatingExpensesExcludingFuel
Operation Exc'l. Fuel
(h)
Fuel Production Expenses
(i)
MaintenanceProductionExpenses
Maintenance Production Expenses
(j)
FuelKind
Kind of Fuel
(k)
FuelCostPerMmbtus
Fuel Costs (in cents (per Million Btu)
(l)
1
HYDROELECTRIC GENERATING PLANTS:
2
Alta FERC No.2310
1902
1
1
3,433,609
13,634,782
13,634,782
473,285
168,542
Water
3
Centerville FERC No.803
1904
6.4
6.4
17,463,863
2,728,729
4,578,183
1,535,036
Water
4
Chili Bar FERC No.2155
1965
7.02
7
27,228,445
18,075,458
2,574,852
244,807
500,828
Water
5
(a)
Coal Canyon
1907
7,575,676
80,538
166,093
Water
6
Cow Creek FERC No.606
1907
1.44
1.8
3,745,421
3,182,941
2,210,376
599,246
760,391
Water
7
Crane Valley FERC No.1354
1919
0.99
0.9
164,934
23,258,096
23,493,026
143,070
324,827
Water
8
Deer Creek FERC No.2310
1908
5.5
5.7
19,144,298
87,621,177
15,931,123
79,345
800,176
Water
9
(b)
Hamilton Branch
1921
5.39
4.8
4,459,717
8,588,805
1,593,470
329,025
242,458
Water
10
Inskip FERC No.1121
1979
7.65
8
20,395,346
2,666,058
565,747
1,665,751
Water
11
Kern Canyon FERC No. 178
1921
9.54
11.5
12,783,346
1,339,973
219,723
23,179
Water
12
Kilarc FERC No.606
1904
3
1.6
8,327,693
4,332,045
1,444,015
651,369
995,956
Water
13
(c)
Lime Saddle
1906
2
2
3,017,132
17,455,558
6,252,102
7,201,744
2,600,320
Water
14
(d)
Merced Falls FERC No.2467
1930
7,276
Water
15
Oak Flat FERC No.2105
1985
1.4
1.3
2,329,025
8,783,381
6,273,844
234,414
124,139
Water
16
Phoenix FERC No.1061
1940
1.6
2
5,653,449
15,380,576
9,612,860
314,765
520,069
Water
17
Potter Valley FERC No.77
1910
9.46
9.2
13,090,222
49,156,531
5,196,251
2,294,948
651,598
Water
18
San Joaquin No. 1-A FERC No.1354
1919
0.42
0.4
32,149,806
76,547,157
87,621
119,918
Water
19
San Joaquin No. 2 FERC No.1354
1917
2.88
3.2
354,930
33,153,732
11,511,713
270,693
83,938
Water
20
San Joaquin No. 3 FERC No.1354
1923
4
4.2
27,525,753
6,881,438
339,866
97,591
Water
21
South FERC No.1121
1979
6.75
7
25,089,079
16,992,536
2,517,413
610,803
1,295,775
Water
22
Spaulding No. 1 FERC No.2310
1928
7.04
7
4,491,409
41,924,150
5,955,135
509,726
250,474
Water
23
Spaulding No. 2 FERC No.2310
1928
3.7
4.4
8,860,840
18,521,493
5,005,809
477,656
127,861
Water
24
Spaulding No. 3 FERC No.2310
1929
6.61
5.8
7,041
15,054,898
2,277,594
486,954
173,348
Water
25
Spring Gap FERC No.2130
1921
6
7
29,954,655
12,171,407
2,028,568
360,510
591,597
Water
26
Toadtown FERC No.803
1986
1.8
1.5
3,519,807
7,287,347
4,048,526
3,679,455
1,149,569
Water
27
Tule FERC No.1333
1914
4.5
6.4
2,521,561
15,026,350
3,339,189
125,923
315,448
Water
28
Volta No.1 FERC No.1121
1980
8.55
9
49,310,273
17,552,924
2,052,974
802,146
1,752,044
Water
29
Volta No.2 FERC No.1121
1981
0.95
0.9
5,326,779
3,105,076
3,268,501
631,006
535,040
Water
30
Wise II FERC No.2310
1986
2.87
3.2
33,782
13,170,152
4,588,903
11,404
338,816
Water
31
(e)
Miscellaneous Minor
16,701,986
Water
33
Photo Voltaic Generating Plants:
34
AT&T PARK SOLAR ARRAYS
2007
0.11
0.1
130,251
1,990,928
17,936,287
37,749
Solar
35
SF SERVICE CENTER SOLAR ARRAY 1 & 2
2007
0.18
0.2
61,799
72,959
405,327
6,252
Solar
36
Vaca Dixon Solar Station
2009
2
2
4,068,953
10,881,965
5,440,983
30,371
12,108
Solar
37
Five Points - Schindler Solar Station #1
2011
15
15
28,699,174
54,818,128
3,654,542
74,716
97,869
Solar
38
Westside - Schindler Solar Station #2
2011
15
15
28,707,717
48,312,358
3,220,824
73,474
193,073
Solar
39
Stroud Solar Station
2011
20
20
37,339,126
62,321,706
3,116,085
79,928
136,135
Solar
40
Cantua Solar Station
2012
20
20
42,223,391
56,349,026
2,817,451
41,083
360,795
Solar
41
Giffen Solar Station
2012
10
10
18,948,350
31,412,761
3,141,276
43,481
60,308
Solar
42
Huron Solar Station
2012
20
20
41,312,760
61,197,254
3,059,863
59,963
249,295
Solar
43
Gates Solar Station
2013
20
20
43,311,245
65,649,055
3,282,453
35,884
69,204
Solar
44
West Gates Solar Station
2013
10
10
21,698,973
77,128,541
7,712,854
43,254
68,180
Solar
45
Guernsey Solar Station
2013
20
20
43,716,766
35,775,278
1,788,764
190,920
214,138
Solar
101
Fuel Cell:
102
San Francisco State
2011
1.6
1.6
11,119,388
8,504,503
5,315,314
257,698
280,948
Natural Gas
103
California State University East Bay
2011
1.4
1.4
4,801,495
6,582,640
4,701,886
129,892
166,927
Natural Gas
105
INTERNAL COMBUSTION:
106
(EMERGENCY STANDBY UNITS)
107
Downieville Diesel Plant
1966
0.75
95,289
Diesel
108
Grass Valley Mobile Diesel Generator
1971
0.25
38,497
Diesel
109
Sierra City Mobile Diesel Generator
1972
0.33
49,054
Diesel


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PlantName

No federal license required. This power plant was retired on April 1, 2013.

(b) Concept: PlantName

No federal license required.

(c) Concept: PlantName

No federal license required.

(d) Concept: PlantName

This hydroelectric plant was sold to Merced Irrigation District on April 16, 2017.

(e) Concept: PlantName

No federal license required.


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
ENERGY STORAGE OPERATIONS (Large Plants)
  1. Large Plants are plants of 10,000 KW or more.
  2. In columns (a) (b) and (c) report the name of the energy storage project, functional classification (Production, Transmission, Distribution), and location.
  3. In column (d), report Megawatt hours (MWH) purchased, generated, or received in exchange transactions for storage.
  4. In columns (e), (f) and (g) report MWHs delivered to the grid to support production, transmission and distribution. The amount reported in column (d) should include MWHs delivered/provided to a generator’s own load requirements or used for the provision of ancillary services.
  5. In columns (h), (i), and (j) report MWHs lost during conversion, storage and discharge of energy.
  6. In column (k) report the MWHs sold.
  7. In column (l), report revenues from energy storage operations. In a footnote, disclose the revenue accounts and revenue amounts related to the income generating activity.
  8. In column (m), report the cost of power purchased for storage operations and reported in Account 555.1, Power Purchased for Storage Operations. If power was purchased from an affiliated seller specify how the cost of the power was determined. In columns (n) and (o), report fuel costs for storage operations associated with self-generated power included in Account 501 and other costs associated with self-generated power.
  9. In columns (q), (r) and (s) report the total project plant costs including but not exclusive of land and land rights, structures and improvements, energy storage equipment, turbines, compressors, generators, switching and conversion equipment, lines and equipment whose primary purpose is to integrate or tie energy storage assets into the power grid, and any other costs associated with the energy storage project included in the property accounts listed.
Line No.
Name of the Energy Storage Project
(a)
Functional Classification
(b)
Location of the Project
(c)
MWHs
(d)
MWHs delivered to the grid to support Production
(e)
MWHs delivered to the grid to support Transmission
(f)
MWHs delivered to the grid to support Transmission
(g)
MWHs Lost During Conversion, Storage and Discharge of Energy Production
(h)
MWHs Lost During Conversion, Storage and Discharge of Energy Transmission
(i)
MWHs Lost During Conversion, Storage and Discharge of Energy Distribution
(j)
MWHs Sold
(k)
Revenues from Energy Storage Operations
(l)
Power Purchased for Storage Operations (555.1) (Dollars)
(m)
Fuel Costs from associated fuel accounts for Storage Operations Associated with Self- Generated Power (Dollars)
(n)
Other Costs Associated with Self-Generated Power (Dollars)
(o)
Project Costs included in
(p)
Production (Dollars)
(q)
Transmission (Dollars)
(r)
Distribution (Dollars)
(s)
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 TOTAL


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION LINE STATISTICS
  1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
  2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page.
  3. Report data by individual lines for all voltages if so required by a State commission.
  4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
  5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line.
  6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.
  7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g).
  8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.
  9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company.
  10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
DESIGNATION VOLTAGE (KV) - (Indicate where other than 60 cycle, 3 phase) LENGTH (Pole miles) - (In the case of underground lines report circuit miles) COST OF LINE (Include in column (j) Land, Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
OperatingVoltageOfTransmissionLine
Operating
DesignedVoltageOfTransmissionLine
Designated
SupportingStructureOfTransmissionLineType
Type of Supporting Structure
LengthForStandAloneTransmissionLines
On Structure of Line Designated
LengthForTransmissionLinesAggregatedWithOtherStructures
On Structures of Another Line
NumberOfTransmissionCircuits
Number of Circuits
SizeOfConductorAndMaterial
Size of Conductor and Material
CostOfLandAndLandRightsTransmissionLines
Land
ConstructionAndOtherCostsTransmissionLines
Construction Costs
OverallCostOfTransmissionLine
Total Costs
OperatingExpensesOfTransmissionLine
Operation Expenses
MaintenanceExpensesOfTransmissionLine
Maintenance Expenses
RentExpensesOfTransmissionLine
Rents
OverallExpensesOfTransmissionLine
Total Expenses
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
1
(a)
DIABLO
GATES #1
500
500
79.23
1
2300 - AAC - BUND
2
(b)
DIABLO
MIDWAY #2
500
500
84.07
1
2300 - AAC - BUND
3
(c)
DIABLO
MIDWAY #3
500
500
84.67
1
2300 - AAC - BUND
4
(d)
DIABLO UNIT #1
500
500
0.54
1
2300 - AAC - BUND
5
(e)
DIABLO UNIT #2
500
500
0.57
1
2300 - AAC - BUND
6
(f)
GATES
MIDWAY
500
500
63.78
1
2300 - AAC - BUND
7
(g)
LOS BANOS
GATES #1
500
500
80.85
1
2300 - AAC - BUND
8
(h)
LOS BANOS
MIDWAY #2
500
500
144.82
1
2300 - AAC - BUND
9
(i)
MALIN
ROUND MTN #2
500
500
46.9
1
2300 - AAC - BUND
10
(j)
MIDWAY
WHIRLWIND
500
500
52.77
1
2156 - ACSR - BUN
11
(k)
MOSS LANDING
LOS BANOS
500
500
51.33
1
2300 - AAC - BUND
12
(l)
MOSS LANDING
METCALF
500
500
34.98
1
2300 - AAC - BUND
13
(m)
ROUND MTN
TABLE MTN #1
500
500
89.03
1
2300 - AAC - BUND
14
(n)
ROUND MTN
TABLE MTN #2
500
500
89.02
1
2300 - AAC - BUND
15
(o)
TABLE MTN
TESLA
500
500
134.99
1
2300 - AAC - BUND
16
(p)
TABLE MTN
VACA
500
500
83.3
1
2300 - AAC - BUND
17
(q)
TESLA
LOS BANOS #1
500
500
57.14
1
2300 - AAC - BUND
18
(r)
TESLA
METCALF
500
500
35.31
1
2300 - AAC - BUND
19
(s)
TESLA
TRACY
500
500
1.13
1
2300 - AAC - BUND
20
(t)
TRACY
LOS BANOS
500
500
56.23
1
2300 - AAC - BUND
21
(u)
VACA
TESLA
500
500
57
1
2300 - AAC - BUND
22
ARCO
MIDWAY
230
230
43.36
1
795 - ACSR - SING
23
ATLANTIC
GOLD HILL
230
230
11.11
1
1113 - AAC - SING
24
(v)
BAHIA
MORAGA
230
230
26.92
1
954 - ACSR - SING
25
BAKERSFIELD #1 TAP
230
230
6.67
1
1113 - AAC - SING
26
BAKERSFIELD #2 TAP
230
230
7.01
1
1113 - AAC - SING
27
BALCH
MCCALL
230
230
39.76
1
954 - AAC - SINGL
28
BELDEN TAP
230
230
0.02
1
795 - ACSR - SING
29
BELLOTA
COTTLE
230
230
19.87
1
1113 - AAC - SING
30
(w)
BELLOTA
TESLA #2
230
230
37.94
1
954 - ACSS - SING
31
BELLOTA
WARNERVILLE
230
230
22.47
1
954 - ACSR - SING
32
(x)
BELLOTA
WEBER
230
230
14.26
1
954 - ACSS - SING
33
BIRDS LANDING SW STA
SHILOH
230
230
0.11
1
954 - AAC - SINGL
34
BIRDS LANDING SW STA
CONTRA COSTA PP
230
230
10.2
1
1113 - ACSS - SIN
35
BIRDS LANDING SW STA
CONTRA COSTA SUB
230
230
9.46
1
1113 - ACSS - SIN
36
BIRDS LANDING SW STA
RUSSELL
230
230
0.11
1
1431 - AAC - SING
37
BLACK TAP
230
230
0.51
1
795 - ACSR - SING
38
(y)
BORDEN
GREGG
230
230
6.21
1
1113 - AAC - SING
39
BOTTLE ROCK TAP D.W.R.
230
230
1.07
1
1113 - AAC - SING
40
BRENTWOOD
KELSO
230
230
16.41
1
1113 - AAC - SING
41
BRIGHTON
BELLOTA
230
230
42.51
1
2300 - AAC - SING
42
BUCKS CREEK
ROCK CREEK-CRESTA
230
230
9.39
1
795 - ACSR - SING
43
BUENA VISTA PUMPING PLANT #
230
230
1.18
1
1113 - AAC - SING
44
BUENA VISTA PUMPING PLANT #
230
230
1.21
1
1113 - AAC - SING
45
BURNEY FOREST PRODUCTS TAP
230
230
0.04
1
795 - ACSR - SING
46
CALIENTE SW STA
MIDWAY #1
230
230
27.17
1
954 - ACSS - SING
47
CALIENTE SW STA
MIDWAY #2
230
230
27.16
1
954 - ACSS - SING
48
CALIFORNIA FLATS SW STA
GATES
230
230
22.57
1
1113 - AAC - SING
49
CAMANCHE PUMPING PLANT TAP
230
230
0.45
1
1113 - AAC - SING
50
CARBERRY SW STA
ROUND MTN
230
230
12.61
1
500 - CU - SINGLE
51
CARIBOU
TABLE MTN
230
230
54.34
1
954 - AAC - SINGL
52
CASTRO VALLEY
NEWARK
230
230
22.71
1
954 - AAC - SINGL
53
COBURN
LAS AGUILAS SW STA
230
230
63.97
1
1113 - AAC - SING
54
COLGATE
RIO OSO
230
230
40.89
1
795 - ACSS - SING
55
CONTRA COSTA
BRENTWOOD
230
230
10.06
1
954 - ACSR - SING
56
CONTRA COSTA
DELTA SWITCHYARD
230
230
18.46
1
954 - ACSR - SING
57
CONTRA COSTA
LAS POSITAS
230
230
23.83
1
954 - ACSS - SING
58
CONTRA COSTA
LONE TREE
230
230
5.62
1
954 - ACSS - SING
59
CONTRA COSTA
MORAGA #1
230
230
26.76
1
954 - ACSS - SING
60
CONTRA COSTA
MORAGA #2
230
230
26.84
1
954 - ACSS - SING
61
CONTRA COSTA PP
CONTRA COSTA SUB
230
230
1.89
1
1113 - ACSS - SIN
62
CORTINA
VACA
230
230
53.29
1
954 - ACSR - SING
63
COTTLE
MELONES
230
230
25.94
1
795 - ACSR - SING
64
COTTONWOOD
DELEVAN #1
230
230
71.55
1
954 - ACSR - SING
65
COTTONWOOD
GLENN
230
230
48.33
1
643.7 - SINGLE 95
66
COTTONWOOD
LOGAN CREEK
230
230
59.28
1
643.7 - SINGLE 11
67
COTTONWOOD
DELEVAN #2
230
230
71.54
1
643.7 - SINGLE 95
68
COVE ROAD TAP
230
230
0.11
1
1113 - AAC - SING
69
(z)
COYOTE SW STA
METCALF
230
230
0.88
1
2300 - AAC - BUND
70
CRESTA
RIO OSO
230
230
64.78
1
795 - ACSR - SING
71
DELEVAN
VACA #2
230
230
71.07
1
954 - ACSR - SING
72
DELEVAN
CORTINA
230
230
17.97
1
954 - ACSR - SING
73
DELEVAN
VACA #3
230
230
71.08
1
954 - ACSR - SING
74
DELEVAN
VACA #1
230
230
71.04
1
954 - ACSR - SING
75
DELTA SWITCHING YARD
TESLA
230
230
7.7
1
954 - ACSR - SING
76
DIABLO
MESA
230
230
40.34
1
1113 - AAC - SING
77
DIABLO PP STANDBY SUPPLY
230
230
0.46
1
1113 - AAC - SING
78
DOS AMIGOS PUMPING PLANT
PANOCHE
230
230
23.68
1
795 - ACSR - SING
79
EASTSHORE
SAN MATEO
230
230
12.43
1
954 - ACSS - SING
80
EIGHT MILE ROAD
TESLA
230
230
26.64
1
1113 - AAC - SING
81
EIGHT MILE ROAD
STAGG
230
230
7.2
1
1113 - AAC - SING
82
ELECTRA
BELLOTA
230
230
29.23
1
643.7 - SINGLE 50
83
FIGARDEN #1 TAP
230
230
0.85
1
1250 KCMIL - ALUM
84
FIGARDEN #2 TAP
230
230
0.83
1
1250 KCMIL - ALUM
85
(aa)
FULTON
LAKEVILLE-IGNACIO
230
230
15.84
1
2300 - AAC - SING
86
FULTON
IGNACIO #1
230
230
40.73
1
2300 - AAC - SING
87
(ab)
FULTON
LAKEVILLE
230
230
25.51
1
1113 - AAC - SING
88
FULTON
LAKEVILLE
230
230
1.19
1
3500 KCMIL - ALUM
89
GATES
MUSTANG SW STA #1
230
230
13.17
1
1113 - ACSS - SIN
90
GATES
MUSTANG SW STA #2
230
230
13.18
1
1113 - ACSS - SIN
91
GATES
ARCO
230
230
35.18
1
1113 - AAC - SING
92
GATES
PANOCHE #1
230
230
43.79
1
795 - ACSR - SING
93
GATES
PANOCHE #2
230
230
43.8
1
795 - ACSR - SING
94
GATES
MIDWAY
230
230
63.86
1
795 - ACSR - SING
95
(ac)
GEYSERS #12
FULTON
230
230
24.09
1
1113 - AAC - SING
96
GEYSERS #13 TAP
230
230
2.06
1
1431 - AAC - SING
97
GEYSERS #16 TAP
230
230
1.29
1
1113 - AAC - SING
98
(ad)
GEYSERS #17
FULTON
230
230
26.14
1
1113 - AAC - SING
99
GEYSERS #18 TAP
230
230
0.75
1
1113 - AAC - SING
100
GEYSERS #20 TAP
230
230
0.03
1
1431 - AAC - SING
101
(ae)
GEYSERS #9
LAKEVILLE
230
230
41.71
1
2300 - AAC - BUND
102
GEYSERS #9
LAKEVILLE
230
230
1.24
1
3500 KCMIL - ALUM
103
GLENN
DELEVAN
230
230
37.42
1
954 - ACSR - SING
104
GOLD HILL
EIGHT MILE ROAD
230
230
48.8
1
1113 - AAC - SING
105
GOLD HILL
LODI STIG
230
230
46.67
1
1113 - AAC - SING
106
(af)
GREGG
ASHLAN
230
230
7
1
795 - ACSR - SING
107
(ag)
GREGG
HERNDON #1
230
230
0.6
1
1113 - AAC - BUND
108
(ah)
GREGG
HERNDON #2
230
230
0.63
1
1113 - AAC - BUND
109
H
Z #1
230
230
6.92
1
2500 KCMIL - CU
110
H
Z #2
230
230
6.96
1
2500 KCMIL - CU
111
HAAS
MCCALL
230
230
44.21
1
954 - AAC - SINGL
112
HELM
MCCALL
230
230
30.84
1
1113 - ACSS - SIN
113
(ai)
HELMS
GREGG #1
230
230
60.67
1
1431 - AAC - BUND
114
(aj)
HELMS
GREGG #2
230
230
60.68
1
1431 - AAC - BUND
115
HERNDON
ASHLAN
230
230
6.39
1
795 - ACSR - SING
116
HERNDON
KEARNEY
230
230
10.82
1
1113 - AAC - SING
117
(ak)
HICKS
METCALF
230
230
9.07
1
954 - ACSS - SING
118
(al)
IGNACIO
SOBRANTE
230
230
42.49
1
2300 - AAC - BUND
119
JEFFERSON
MARTIN
230
230
3.31
1
954 - ACSS - SING
120
JEFFERSON
MARTIN
230
230
24.41
1
2500 KCMIL - CU
121
KELSO
TESLA
230
230
7.95
1
954 - ACSS - SING
122
LAKEVILLE
IGNACIO #2
230
230
14.53
1
1113 - AAC - SING
123
(am)
LAKEVILLE
IGNACIO #1
230
230
15.49
1
2300 - AAC - BUND
124
(an)
LAKEVILLE
SOBRANTE #2
230
230
47.89
1
2156 - ACSS - SIN
125
LAKEVILLE
TULUCAY
230
230
17.22
1
1 - UNKNOWN - UNK
126
(ao)
LAKEVILLE
TULUCAY
230
230
0.06
1
1 - UNKNOWN - UNK
127
LAMBIE SW STA
BIRDS LANDING SW STA
230
230
7.04
1
1113 - ACSS - SIN
128
LAS AGUILAS SW STA
PANOCHE #2
230
230
17.44
1
795 - ACSR - SING
129
LAS AGUILAS SW STA
PANOCHE #1
230
230
17.44
1
795 - ACSR - SING
130
LAS POSITAS
NEWARK
230
230
20.93
1
795 - ACSR - SING
131
LOCKEFORD
BELLOTA
230
230
12.32
1
2300 - AAC - SING
132
LODI STIG
EIGHT MILE ROAD
230
230
2.18
1
1113 - AAC - SING
133
LOGAN CREEK
DELEVAN
230
230
12.35
1
954 - ACSR - SING
134
LONE TREE
CAYETANO
230
230
15.4
1
954 - ACSS - SING
135
LONE TREE
CAYETANO
230
230
2.3
1
2000 KCMIL - CU
136
LOS BANOS
DOS AMIGOS
230
230
14.31
1
795 - ACSR - SING
137
LOS BANOS
PANOCHE #1
230
230
37.18
1
1113 - AAC - SING
138
LOS BANOS
PANOCHE #2
230
230
37.13
1
1113 - AAC - SING
139
LOS BANOS
SAN LUIS PUMPS #1
230
230
3.43
1
1113 - AAC - SING
140
LOS BANOS
SAN LUIS PUMPS #2
230
230
3.43
1
1113 - AAC - SING
141
(ap)
LOS BANOS
QUINTO SW STA
230
230
12.06
1
795 - ACSS - PARA
142
(aq)
LOS ESTEROS
METCALF
230
230
63.25
1
795 - ACSR - PARA
143
LOS ESTEROS
METCALF
230
230
2.73
1
2500 KCMIL - CU
144
MALACHA TAP
230
230
0.12
1
954 - ACSR - SING
145
MELONES
WILSON
230
230
61.61
1
795 - ACSR - SING
146
(ar)
METCALF
MONTA VISTA #3
230
230
28.59
1
2300 - AAC - BUND
147
(as)
METCALF
MOSS LANDING #1
230
230
35.76
1
954 - ACSS - SING
148
(at)
METCALF
MOSS LANDING #2
230
230
35.76
1
954 - ACSS - SING
149
MIDDLE FORK
GOLD HILL
230
230
44.08
1
1113 - AAC - SING
150
(au)
MIDWAY
KERN #1
230
230
41.75
1
795 - ACSR - SING
151
(av)
MIDWAY
KERN #3
230
230
20.88
1
1113 - AAC - SING
152
(aw)
MIDWAY
KERN #4
230
230
20.84
1
1113 - AAC - BUND
153
MIDWAY
WHEELER RIDGE #1
230
230
52.68
1
1113 - AAC - SING
154
(ax)
MIDWAY
SUNSET
230
230
0.57
1
1431 - AAC - SING
155
MIDWAY
WHEELER RIDGE #2
230
230
52.65
1
1113 - AAC - SING
156
(ay)
MONTA VISTA
COYOTE SW STA
230
230
27.83
1
2300 - AAC - BUND
157
(az)
MONTA VISTA
HICKS
230
230
13.27
1
954 - ACSS - SING
158
(ba)
MONTA VISTA
JEFFERSON #1
230
230
19.72
1
1113 - AAC - SING
159
(bb)
MONTA VISTA
JEFFERSON #2
230
230
19.73
1
1113 - AAC - SING
160
MONTA VISTA
SARATOGA
230
230
5.49
1
1113 - AAC - SING
161
MONTEZUMA SW STA
BIRDS LANDING SW STA
230
230
0.54
1
1431 - AAC - SING
162
MORAGA
CASTRO VALLEY
230
230
14.92
1
954 - ACSR - SING
163
MORRO BAY
DIABLO
230
230
15.78
1
1113 - AAC - SING
164
MORRO BAY
CALIFORNIA FLATS SW STA
230
230
46.19
1
954 - AAC - SINGL
165
MORRO BAY
MESA
230
230
35.27
1
1113 - AAC - SING
166
MORRO BAY
SOLAR SW STA #1
230
230
45.55
1
954 - ACSS - SING
167
MORRO BAY
SOLAR SW STA #2
230
230
45.56
1
954 - ACSS - SING
168
MORRO BAY
TEMPLETON
230
230
16.43
1
954 - AAC - SINGL
169
MOSS LANDING
COBURN
230
230
64.03
1
795 - ACSR - SING
170
MOSS LANDING
LAS AGUILAS SW STA
230
230
51.89
1
795 - ACSR - SING
171
MOSS LANDING INTERPLANT 230
230
230
0.13
1
2300 - AAC - SING
172
MOSS LANDING TX BK 1
230 SWITCHYARD
230
230
0.24
1
1113 - AAC - SING
173
MOSS LANDING TX BK 2
230 SWITCHYARD
230
230
0.16
1
500 - SINGLE
174
MUSTANG SW STA
GREGG
230
230
45.47
1
1113 - ACSS - SIN
175
MUSTANG SW STA
MCCALL
230
230
42.11
1
1113 - ACSS - SIN
176
(bc)
NEWARK
LOS ESTEROS
230
230
5.65
1
1113 - AAC - BUND
177
(bd)
NEWARK
RAVENSWOOD
230
230
8.91
1
954 - ACSS - BUND
178
NEWARK
LOS ESTEROS
230
230
2.75
1
2500 KCMIL - CU
179
(be)
NEWARK E
F BUS TIE
230
230
0.22
1
1113 - AAC - BUND
180
NORTH DUBLIN
CAYETANO
230
230
3.02
1
954 - ACSS - SING
181
NORTH DUBLIN
VINEYARD
230
230
12.46
1
954 - ACSS - SING
182
NORTH DUBLIN
CAYETANO
230
230
2.81
1
2000 KCMIL - CU
183
NORTH DUBLIN
VINEYARD
230
230
11.07
1
184
PALERMO
COLGATE
230
230
29.6
1
795 - ACSS - SING
185
(bf)
PANOCHE
PANOCHE ENERGY CENTER
230
230
0.09
1
1113 - AAC - BUND
186
PANOCHE
TRANQUILLITY SW STA #1
230
230
12.14
1
1113 - ACSS - SIN
187
PANOCHE
TRANQUILLITY SW STA #2
230
230
12.14
1
1113 - ACSS - SIN
188
PARKWAY
MORAGA
230
230
23.64
1
954 - ACSR - SING
189
PEABODY
BIRDS LANDING SW STA
230
230
19.85
1
1113 - ACSS - SIN
190
PIT #1
COTTONWOOD
230
230
59.75
1
500 - CU - SINGLE
191
PIT #3
PIT #1
230
230
22.69
1
518 - ACSR - SING
192
PIT #3
CARBERRY SW STA
230
230
10.91
1
795 - ACSR - SING
193
PIT #4 TAP
230
230
7.03
1
795 - ACSR - SING
194
PIT #5
ROUND MTN #1
230
230
13.12
1
795 - ACSR - SING
195
PIT #5
ROUND MTN #2
230
230
13.11
1
795 - ACSR - SING
196
PIT #6 JCT
ROUND MTN
230
230
8.15
1
795 - ACSR - SING
197
PIT #6 TAP
230
230
3.43
1
795 - ACSR - SING
198
PIT #7 TAP
230
230
3.59
1
795 - ACSR - SING
199
PITTSBURG
EASTSHORE
230
230
34.92
1
954 - ACSS - SING
200
PITTSBURG
SAN MATEO
230
230
47.4
1
954 - ACSS - SING
201
(bg)
PITTSBURG
TASSAJARA
230
230
17.36
1
954 - ACSS - SING
202
PITTSBURG
SAN RAMON
230
230
21.66
1
954 - ACSS - SING
203
(bh)
PITTSBURG
TESORO
230
230
11.27
1
2300 - AAC - BUND
204
(bi)
PITTSBURG
TESLA #1
230
230
31.35
1
1113 - AAC 954 -
205
(bj)
PITTSBURG
TESLA #2
230
230
31.32
1
954 - ACSS - SING
206
(bk)
PITTSBURG
TIDEWATER
230
230
11.27
1
2300 - AAC - BUND
207
POE
RIO OSO
230
230
56.09
1
795 - ACSR - SING
208
(bl)
QUINTO SW STA
WESTLEY
230
230
57.55
1
795 - ACSS - PARA
209
RALPH TAP
230
230
0.06
1
1113 - AAC - SING
210
RANCHO SECO
BELLOTA #1
230
230
27.39
1
2300 - AAC - SING
211
RANCHO SECO
BELLOTA #2
230
230
27.36
1
2300 - AAC - SING
212
(bm)
RAVENSWOOD
SAN MATEO #2
230
230
11.88
1
1113 - AAC - BUND
213
(bn)
RAVENSWOOD
SAN MATEO #1
230
230
11.89
1
1113 - AAC - BUND
214
RIO OSO
ATLANTIC
230
230
17.68
1
1113 - AAC - SING
215
RIO OSO
BRIGHTON
230
230
27.17
1
795 - ACSR - SING
216
RIO OSO
GOLD HILL
230
230
28.63
1
1113 - AAC - SING
217
RIO OSO
LOCKEFORD
230
230
65.13
1
1113 - AAC - SING
218
ROCK CREEK
POE
230
230
26.98
1
795 - ACSR - SING
219
ROSSMOOR #1 TAP
230
230
0.69
1
1113 - AAC - SING
220
ROSSMOOR #2 TAP
230
230
0.66
1
1113 - AAC - SING
221
ROUND MTN
COTTONWOOD #2
230
230
33.67
1
795 - ACSR - SING
222
ROUND MTN
COTTONWOOD #3
230
230
33.36
1
500 - CU - SINGLE
223
(bo)
RUSSELL CITY ENERGY CENTER
EASTSHORE #1
230
230
1.19
1
1113 - AAC - BUND
224
(bp)
RUSSELL CITY ENERGY CENTER
EASTSHORE #2
230
230
1.2
1
1113 - AAC - BUND
225
SAN MATEO
MARTIN
230
230
13
1
3500 KCMIL
226
SAN RAMON
MORAGA
230
230
22.24
1
954 - ACSR - SING
227
SAN RAMON RESEARCH CENTER T
230
230
3.27
1
1113 - AAC - SING
228
SANTA FE GEOTHERMAL TAP
230
230
1.04
1
1113 - AAC - SING
229
SARATOGA
VASONA
230
230
3.41
1
954 - ACSS - SING
230
SHILOH II
BIRDS LANDING SW STA
230
230
3.56
1
1431 - AAC - SING
231
SOLAR SW STA
CALIENTE SW STA #1
230
230
8.22
1
954 - ACSS - SING
232
SOLAR SW STA
CALIENTE SW STA #2
230
230
8.22
1
954 - ACSS - SING
233
SPI (BURNEY) TAP
230
230
0.05
1
795 - ACSR - SING
234
STAGG
TESLA
230
230
23.64
1
1113 - AAC - SING
235
STOCKDALE #1 TAP
230
230
6.23
1
795 - ACSR - SING
236
STOCKDALE #2 TAP
230
230
6.14
1
1113 - AAC - SING
237
TABLE MTN
PALERMO
230
230
14.57
1
795 - ACSS - SING
238
TABLE MTN
RIO OSO
230
230
50.17
1
795 - ACSS - SING
239
TASSAJARA
NEWARK
230
230
31.8
1
954 - AAC - SINGL
240
TEMPLETON
GATES
230
230
52.18
1
1113 - AAC - SING
241
TES TAP
230
230
3.28
1
1113 - AAC - SING
242
(bq)
TESLA
NEWARK #2
230
230
40.88
1
954 - ACSS - PARA
243
(br)
TESLA
NEWARK #1
230
230
28.19
1
2300 - AAC - BUND
244
(bs)
TESLA
RAVENSWOOD
230
230
37.14
1
2300 - AAC - BUND
245
TESLA
TRACY #1
230
230
5.68
1
954 - ACSS - SING
246
TESLA
TRACY #2
230
230
5.68
1
954 - ACSS - SING
247
(bt)
TESLA
WESTLEY
230
230
45.06
1
795 - ACSR - BUND
248
(bu)
TESORO
SOBRANTE
230
230
12.32
1
2300 - AAC - BUND
249
(bv)
TIDEWATER
SOBRANTE
230
230
12.32
1
2300 - AAC - BUND
250
TIGER CREEK
ELECTRA
230
230
13.65
1
1113 - AAC - SING
251
TIGER CREEK
VALLEY SPRINGS
230
230
24.22
1
1113 - AAC - SING
252
TRANQUILLITY SW STA
HELM
230
230
12.68
1
1113 - ACSS - SIN
253
TRANQUILLITY SW STA
KEARNEY
230
230
36.9
1
1113 - ACSS - SIN
254
TULUCAY
VACA
230
230
23.63
1
954 - ACSR - SING
255
US WINDPOWER #3 TAP
230
230
0.06
1
1113 - AAC - SING
256
(bw)
VACA
BAHIA
230
230
33.9
1
954 - ACSR - SING
257
VACA
PEABODY
230
230
9.69
1
1113 - ACSS - SIN
258
VACA
LAKEVILLE #1
230
230
40.93
1
954 - ACSR - SING
259
VACA
LAMBIE SW STA
230
230
13.95
1
1113 - ACSS - SIN
260
VACA
PARKWAY
230
230
27.76
1
954 - ACSR - SING
261
VACA DIXON
MORAGA #1
230
230
3.08
1
954 - ACSS - SING
262
VALLEY SPRINGS
BELLOTA
230
230
20.67
1
643.7 - SINGLE 50
263
VASONA
METCALF
230
230
13.29
1
954 - ACSS - SING
264
VINEYARD
NEWARK
230
230
14.36
1
795 - ACSR - SING
265
VINEYARD
NEWARK
230
230
5.94
1
2000 KCMIL - CU
266
WARNERVILLE
WILSON
230
230
38.4
1
954 - ACSR - SING
267
(bx)
WEBER
TESLA
230
230
23.71
1
954 - ACSS - SING
268
WHEELER RIDGE PUMPING PLANT
230
230
0.25
1
1113 - AAC - SING
269
WHEELER RIDGE PUMPING PLANT
230
230
0.23
1
1113 - AAC - SING
270
(by)
WILSON
GREGG
230
230
41.44
1
795 - ACSR - SING
271
WILSON
BORDEN
230
230
35.37
1
500 - SINGLE 1113
272
WIND GAP PUMPING PLANT #1 T
230
230
1.64
1
1113 - AAC - SING
273
WIND GAP PUMPING PLANT #2 T
230
230
1.62
1
1113 - AAC - SING
274
WINDMASTER TAP
230
230
0.11
1
1113 - AAC - SING
275
ZA
1
230
230
3.41
1
2000 KCMIL - CU
276
7TH STANDARD
KERN
115
115
6.75
1
715.5 - AAC - SIN
277
A
P #1
115
115
2.46
1
3500 KCMIL - CU
278
A
H-W #1
115
115
4.95
1
1250 KCMIL - CU
279
A
X #1
115
115
2.67
1
1250 KCMIL
280
A
Y #1
115
115
3.33
1
1250 KCMIL - CU
281
A
Y #2
115
115
2.85
1
3000 KCMIL - ALUM
282
A
H-W #2
115
115
5.06
1
1250 KCMIL
283
ADOBE SW STA
LAMONT
115
115
21.2
1
715.5 - AAC - SIN
284
AEC SITE #1 TAP
115
115
1.6
1
4/0 - AAC - SINGL
285
AEC SITE #2 TAP
115
115
2.16
1
286
AGNEW TAP
115
115
1.32
1
715.5 - AAC - SIN
287
AIR PRODUCTS TAP
115
115
0.29
1
4/0 - AAC - SINGL
288
AMERIGAS TAP
115
115
0.49
1
715.5 - AAC - SIN
289
AMES DISTRIBUTION
AMES
115
115
0.1
1
715.5 - AAC - SIN
290
APPLE HILL #1 TAP
115
115
1.42
1
4/0 - AAC - SINGL
291
APPLE HILL #2 TAP
115
115
1.43
1
397.5 - AAC - SIN
292
APPLIED MATERIALS
BRITTON
115
115
0.47
1
477 - ACSS - SING
293
APPLIED MATERIALS
BRITTON
115
115
0.74
1
2500 KCMIL - CU
294
ARVIN EDISON TAP
115
115
1.06
1
397.5 - AAC - SIN
295
ATLANTIC
PLEASANT GROVE #1
115
115
5.33
1
477 - ACSS - SING
296
ATLANTIC
PLEASANT GROVE #2
115
115
5.36
1
715.5 - AAC - SIN
297
ATWATER
EL CAPITAN
115
115
7.31
1
715.5 - AAC - SIN
298
ATWATER
LIVINGSTON-MERCED
115
115
24.26
1
715.5 - AAC - SIN
299
ATWATER
CRESSEY
115
115
5.91
1
715.5 - AAC - SIN
300
BADGER CREEK (PSE) TAP
115
115
1.07
1
715.5 - AAC - SIN
301
BAIR
BELMONT
115
115
3.64
1
477 - ACSS - SING
302
BALCH
SANGER
115
115
35.62
1
715.5 - AAC - SIN
303
BARKER SLOUGH TAP
115
115
1.62
1
4/0 - AAC - SINGL
304
BARTON
AIRWAYS-SANGER
115
115
11.65
1
2300 - AAC - SING
305
BEAR MTN TAP
115
115
1.27
1
715.5 - AAC - SIN
306
BEARDSLEY TAP
115
115
2.2
1
4/0 - ACSR - SING
307
BELL
PLACER
115
115
7.94
1
715.5 - AAC - SIN
308
BELLOTA
RIVERBANK-MELONES SW STA
115
115
44.65
1
715.5 - AAC - SIN
309
BELLOTA
RIVERBANK
115
115
18.87
1
715.5 - AAC - SIN
310
BELRIDGE TAP
115
115
6.94
1
715.5 - AAC - SIN
311
(bz)
BIG BEND
CLAYTON #1
115
0.02
1
312
BOGUE
RIO OSO
115
115
21.24
1
1113 - AAC - SING
313
BOLLMAN #1 TAP
115
115
2.14
1
4/0 - AAC - SINGL
314
BOLLMAN #2 TAP
115
115
2.19
1
4/0 - AAC - SINGL
315
BOLTHOUSE FARMS TAP
115
115
0.11
1
4/0 - AAC - SINGL
316
BRIDGEVILLE
COTTONWOOD
115
115
86.06
1
397.5 - ACSR - SI
317
(ca)
BRIGHTON
CLAYTON #1
115
115
6.72
1
3/0 - CU - SINGLE
318
(cb)
BRIGHTON
CLAYTON #2
115
115
6.72
1
3/0 - CU - SINGLE
319
BRIGHTON
DAVIS
115
115
42.73
1
715.5 - AAC - SIN
320
(cc)
BRIGHTON
DAVIS
115
115
17.36
1
715.5 - AAC - SIN
321
(cd)
BRIGHTON
GRAND ISLAND #1
115
115
24.99
1
715.5 - AAC - SIN
322
(ce)
BRIGHTON
GRAND ISLAND #1
115
115
0.14
1
715.5 - AAC - SIN
323
(cf)
BRIGHTON
GRAND ISLAND #2
115
115
25.04
1
715.5 - AAC - SIN
324
(cg)
BRIGHTON
GRAND ISLAND #2
115
115
0.14
1
715.5 - AAC - SIN
325
BRITTON
MONTA VISTA
115
115
7.17
1
477 - ACSS - SING
326
BRUNSWICK #1 TAP
115
115
6.98
1
397.5 - ACSR - SI
327
BRUNSWICK #2 TAP
115
115
7
1
397.5 - ACSR - SI
328
BUELLTON TAP
115
115
1.75
1
397.5 - AAC - SIN
329
(ch)
BUTTE
SYCAMORE CREEK
115
115
18.17
1
715.5 - AAC - SIN
330
BUTTE VALLEY
CARIBOU
115
115
7.42
1
795 - ACSR - SING
331
C
X #3
115
115
3.67
1
3500 KCMIL - CU
332
C
L #1
115
115
1.1
1
3000 KCMIL
333
C
X #2
115
115
3.38
1
1250 KCMIL - CU
334
CABRILLO
SANTA YNEZ SW STA
115
115
14.59
1
715.5 - AAC - SIN
335
CAL PEAK
VACA
115
115
0.11
1
715.5 - AAC - SIN
336
CAL WATER TAP
115
115
2.15
1
715.5 - AAC - SIN
337
CALIFORNIA AVE
MCCALL
115
115
23.66
1
477 - ACSS - SING
338
CALLENDER SW STA
MESA
115
115
13.77
1
715.5 - AAC - SIN
339
CAMANCHE TAP
115
115
6.71
1
4/0 - AAC - SINGL
340
CAMP EVERS
PAUL SWEET
115
115
5.22
1
715.5 - AAC - SIN
341
CANTUA TAP
115
115
1.83
1
397.5 - AAC - SIN
342
CARIBOU
PALERMO
115
115
54.89
1
715.5 - AAC - SIN
343
CARQUINEZ #1 TAP
115
115
0.51
1
397.5 - AAC - SIN
344
CARQUINEZ #2 TAP
115
115
0.52
1
397.5 - AAC - SIN
345
CARRIZO PLAINS TAP
115
115
0.04
1
715.5 - AAC - SIN
346
CASCADE
COTTONWOOD
115
115
19.46
1
250 - CU - SINGLE
347
CAWELO C TAP
115
115
1.33
1
397.5 - AAC - SIN
348
CERTAINTEED TAP
115
115
2.53
1
397.5 - AAC - SIN
349
CHARCA
FAMOSO
115
115
7.15
1
250 - CU - SINGLE
350
CHCF TAP
115
115
3
1
397.5 - AAC - SIN
351
CHENEY #1 TAP
115
115
4.1
1
397.5 - ACSR - SI
352
CHENEY #2 TAP
115
115
1.97
1
397.5 - AAC - SIN
353
CHINESE CAMP (ULTRA POWER)
115
115
2.07
1
4/0 - ACSR - SING
354
CHOWCHILLA
KERCKHOFF
115
115
42.52
1
715.5 - AAC - SIN
355
CHOWCHILLA #1 TAP
115
115
1.25
1
397.5 - AAC - SIN
356
CHRISTIE
SOBRANTE
115
115
7.84
1
715.5 - AAC - SIN
357
CITY #1 TAP
115
115
0.07
1
397.5 - AAC - SIN
358
CITY #2 TAP
115
115
1.37
1
397.5 - AAC - SIN
359
CLAYTON
MEADOW LANE
115
115
7.06
1
715.5 - AAC - SIN
360
COLES LEVEE TAP
115
115
0.22
1
4/0 - AAC - SINGL
361
COLUMBIA SOLAR 115kV TAP
115
115
0.45
1
4/0 - AAC - SINGL
362
CONTRA COSTA #1
115
115
11.15
1
1113 - AAC - SING
363
CONTRA COSTA #2
115
115
1.41
1
3/0 - CU - SINGLE
364
COOLEY LANDING
PALO ALTO
115
115
2.72
1
715.5 - AAC - SIN
365
CORCORAN
OLIVE SW STA
115
115
36.83
1
1113 - AAC - SING
366
CORONA
LAKEVILLE
115
115
5.79
1
477 - ACSS - SING
367
CORTINA
MENDOCINO #1
115
115
60.95
1
397.5 - ACSR - SI
368
COTTONWOOD
PANORAMA
115
115
2.95
1
397.5 - AAC - SIN
369
CRAG VIEW
CASCADE
115
115
21.6
1
250 - CU - SINGLE
370
CRAZY HORSE CANYON
SAN BENITO
115
115
8.95
1
477 - ACSS - SING
371
CRAZY HORSE CANYON
HOLLISTER
115
115
17.23
1
2/0 - CU - SINGLE
372
CRAZY HORSE CANYON
SALINAS-SOLEDAD #1
115
115
35.35
1
3/0 - CU - SINGLE
373
CRAZY HORSE CANYON
SALINAS-SOLEDAD #2
115
115
35.41
1
477 - ACSS - SING
374
CYMRIC TAP
115
115
0.18
1
397.5 - AAC - SIN
375
D
L #1
115
115
2.31
1
3000 KCMIL
376
DAIRYLAND
MENDOTA
115
115
28.69
1
477 - ACSS - SING
377
DANISH CREAMERY TAP
115
115
1.2
1
4/0 - AAC - SINGL
378
DE FRANCESCO TAP
115
115
1.02
1
4/0 - AAC - SINGL
379
DEEPWATER #1 TAP
115
115
2.29
1
715.5 - AAC - SIN
380
DEEPWATER #2 TAP
115
115
2.45
1
715.5 - AAC - SIN
381
DISCOVERY TAP
115
115
2.1
1
715.5 - AAC - SIN
382
DIVIDE
CABRILLO #2
115
115
11.55
1
715.5 - AAC - SIN
383
DIVIDE
CABRILLO #1
115
115
14.6
1
715.5 - AAC - SIN
384
DIXON LANDING
MCKEE
115
115
8.3
1
477 - ACSS - SING
385
DOLAN RD #1 TAP
115
115
0.32
1
266.8 - AAC - SIN
386
DOLAN RD #2 TAP
115
115
0.33
1
266.8 - AAC - SIN
387
DONNELLS
CURTIS
115
115
26.81
1
397.5 - ACSR - SI
388
DOUBLE C (PSE) TAP
115
115
0.06
1
715.5 - AAC - SIN
389
DRUM
RIO OSO #1
115
115
44.64
1
266.8 - AAC - SIN
390
DRUM
RIO OSO #2
115
115
44.65
1
266.8 - AAC - SIN
391
DRUM
SUMMIT #1
115
115
27.36
1
397.5 - ACSR - SI
392
DRUM
SUMMIT #2
115
115
28.36
1
397.5 - ACSR - SI
393
DRUM
HIGGINS
115
115
47.75
1
715.5 - AAC - SIN
394
DRUM PH #2 TAP
115
115
0.09
1
250 - CU - SINGLE
395
DUMBARTON
NEWARK
115
115
7.14
1
795 - ACSS - SING
396
DUTCH FLAT #2 TAP
115
115
0.43
1
397
EAGLE ROCK
CORTINA
115
115
43.38
1
715.5 - AAC - SIN
398
EAGLE ROCK
REDBUD
115
115
23.31
1
715.5 - AAC - SIN
399
(ci)
EAGLE ROCK
FULTON-SILVERADO
115
115
46.94
1
715.5 - AAC - SIN
400
EAST GRAND
SAN MATEO
115
115
7.89
1
477 - ACSS - SING
401
EAST GRAND
SAN MATEO
115
115
0.22
1
3000 KCMIL - ALUM
402
(cj)
EASTSHORE
DUMBARTON
115
115
12.38
1
477 - ACSS - BUND
403
EASTSHORE
MT EDEN #1
115
115
1.04
1
715.5 - AAC - SIN
404
EASTSHORE
MT EDEN #2
115
115
1
1
715.5 - AAC - SIN
405
EASTSHORE
CERBERUS
115
115
0.48
1
397.5 - AAC - SIN
406
EBMUD TAP
115
115
0.02
1
407
EBMUD TAP
115
115
0.94
1
500 KCMIL
408
EDES #1 TAP
115
115
0.05
1
715.5 - AAC - SIN
409
EDES #2 TAP
115
115
0.04
1
715.5 - AAC - SIN
410
EL CAPITAN
WILSON
115
115
8.12
1
715.5 - AAC - SIN
411
EL DORADO
MISSOURI FLAT #1
115
115
14.43
1
715.5 - AAC - SIN
412
EL DORADO
MISSOURI FLAT #2
115
115
14.41
1
715.5 - AAC - SIN
413
EL PATIO
SAN JOSE A
115
115
7.08
1
715.5 - AAC - PAR
414
ELLIS TAP
115
115
0.17
1
4/0 - AAC - SINGL
415
EXCELSIOR SW STA
FIVE POINTS PV
115
115
0.03
1
416
EXCELSIOR SW STA
SCHINDLER #1
115
115
5.24
1
715.5 - AAC 397.5
417
EXCELSIOR SW STA
SCHINDLER #2
115
115
5.23
1
715.5 - AAC 397.5
418
EXCHEQUER
LE GRAND
115
115
29.75
1
266.8 - AAC - SIN
419
FAIRVIEW
MARTINEZ SW STA
115
115
0.1
1
420
FAIRWAY #1 TAP
115
115
2.83
1
266.8 - AAC - SIN
421
FAIRWAY #2 TAP
115
115
1.52
1
397.5 - AAC - SIN
422
FELLOWS
MIDSUN
115
115
4.73
1
715.5 - AAC - SIN
423
FELLOWS
TAFT
115
115
7.93
1
715.5 - AAC - SIN
424
FIBREBOARD STANDARD TAP
115
115
0.02
1
425
FIBREBOARD TAP
115
115
1.03
1
4/0 - AAC - SINGL
426
FLINT TAP
115
115
1.96
1
4/0 - AAC - SINGL
427
FMC
SAN JOSE B
115
115
1.61
1
795 - ACSS - SING
428
FORBESTOWN TAP
115
115
0.22
1
397.5 - ACSR - SI
429
FRITO LAY TAP
115
115
0.53
1
4/0 - AAC - SINGL
430
FROGTOWN #1 TAP
115
115
0.12
1
2/0 - CU - SINGLE
431
FROGTOWN #2 TAP
115
115
0.11
1
2/0 - CU - SINGLE
432
FULTON
PUEBLO
115
115
59.9
1
715.5 - AAC - SIN
433
FULTON
SANTA ROSA #1
115
115
6.69
1
477 - ACSS - SING
434
FULTON
SANTA ROSA #2
115
115
6.29
1
477 - ACSS - SING
435
FULTON JCT
VACA
115
115
11.93
1
477 - ACSS - SING
436
GALLO
LIVINGSTON
115
115
4.2
1
715.5 - AAC - SIN
437
GALLO
CRESSEY
115
115
14.43
1
715.5 - AAC - SIN
438
GEYSERS #11
EAGLE ROCK
115
115
0.64
1
1113 - AAC - SING
439
GEYSERS #3
CLOVERDALE
115
115
12.07
1
715.5 - AAC - SIN
440
GEYSERS #3
EAGLE ROCK
115
115
1.77
1
715.5 - AAC - SIN
441
GEYSERS #5
GEYSERS #3
115
115
0.49
1
715.5 - AAC - SIN
442
GEYSERS #7
EAGLE ROCK
115
115
1.4
1
715.5 - AAC - SIN
443
GILL RANCH TAP
115
115
9.15
1
715.5 - AAC - SIN
444
(ck)
GILROY ENERGY TAP
115
115
0.28
1
715.5 - AAC - BUN
445
(cl)
GISH TAP
115
115
0.96
1
1 - UNKNOWN - UNK
446
GOLD HILL
BELLOTA-LOCKEFORD
115
115
87.28
1
715.5 - AAC - SIN
447
GOLD HILL
CLARKSVILLE
115
115
5.77
1
477 - ACSS - SING
448
GOLDEN VALLEY TAP
115
115
1.59
1
4/0 - AAC - SINGL
449
GOLDTREE TAP
115
115
2.3
1
397.5 - AAC - SIN
450
GRANT
EASTSHORE #1
115
115
4.33
1
715.5 - AAC - SIN
451
GRANT
EASTSHORE #2
115
115
4.2
1
715.5 - AAC - SIN
452
GREEN VALLEY
CAMP EVERS
115
115
18.59
1
715.5 - AAC - SIN
453
GREEN VALLEY
LLAGAS
115
115
24.85
1
715.5 - AAC - SIN
454
GREEN VALLEY
PAUL SWEET
115
115
16.03
1
715.5 - AAC - SIN
455
GREENLEAF #1 TAP
115
115
4.84
1
715.5 - AAC - SIN
456
GRIZZLY TAP (SVP)
115
115
0.16
1
457
GUARDIAN #1 TAP
115
115
0.75
1
4/0 - AAC - SINGL
458
GUARDIAN #2 TAP
115
115
0.13
1
4/0 - AAC - SINGL
459
GWF
KINGSBURG
115
115
21.62
1
1113 - AAC - SING
460
H
P #3
115
115
0.17
1
715.5 - AAC - SIN
461
H
P #4
115
115
5.16
1
3500 KCMIL - CU
462
H
P #1
115
115
3.8
1
1000 KCMIL - CU
463
H
Y #1
115
115
7.23
1
1250 KCMIL - CU
464
H
P #3
115
115
3.59
1
1250 KCMIL - CU
465
(cm)
HEINZ TAP
115
0.79
1
4/0 - AAC - SINGL
466
HENRIETTA
LEPRINO SW STA
115
115
6.03
1
1113 - AAC - SING
467
HERNDON
BARTON
115
115
12.68
1
477 - ACSS 1431 -
468
HERNDON
BULLARD #1
115
115
11.43
1
954 - ACSS - SING
469
HERNDON
BULLARD #2
115
115
11.42
1
954 - ACSS - SING
470
HERNDON
MANCHESTER
115
115
9.27
1
1431 - AAC - SING
471
HERNDON
WOODWARD
115
115
12.97
1
1113 - AAC - SING
472
HIGGINS
BELL
115
115
18.77
1
715.5 - AAC - SIN
473
HONCUT TAP
115
115
1.65
1
4/0 - AAC - SINGL
474
HOWLAND ROAD TAP
115
115
0.9
1
4/0 - AAC - SINGL
475
HUMBOLDT
BRIDGEVILLE
115
115
30.28
1
397.5 - ACSR - SI
476
HUMBOLDT
TRINITY
115
115
68.57
1
4/0 - ACSR - SING
477
HUMBOLDT BAY
HUMBOLDT #1
115
115
6.31
1
397.5 - AAC - SIN
478
IBM BAILEY AVE TAP
115
115
2
1
397.5 - AAC - SIN
479
IBM HARRY RD #1 TAP
115
115
0.58
1
397.5 - AAC - SIN
480
IBM HARRY RD #2 TAP
115
115
0.58
1
397.5 - AAC - SIN
481
IGNACIO
MARE ISLAND #1
115
115
39.48
1
715.5 - AAC - SIN
482
IGNACIO
MARE ISLAND #2
115
115
43.08
1
715.5 - AAC - SIN
483
IGNACIO
SAN RAFAEL #1
115
115
11.54
1
715.5 - AAC - SIN
484
IGNACIO
SAN RAFAEL #3
115
115
8.65
1
715.5 - AAC - SIN
485
IMHOFF TAP
115
115
1.43
1
2 - UNKNOWN - UNK
486
INGRAM CREEK TAP
115
115
0.5
1
4/0 - AAC - SINGL
487
JAMESON CANYON PUMPING PLAN
115
115
0.19
1
4/0 - AAC - SINGL
488
JARVIS
CRYOGENICS
115
115
0.03
1
715.5 - AAC - SIN
489
JESSUP TAP
115
115
0.86
1
397.5 - ACSR - SI
490
K
D #1
115
115
2.44
1
2000 KCMIL - CU
491
K
D #2
115
115
2.57
1
3000 KCMIL - CU
492
KAMM TAP
115
115
0.52
1
4/0 - AAC - SINGL
493
KANAKA TAP
115
115
2.59
1
4/0 - ACSR - SING
494
KANSAS PV
LEPRINO SW STA
115
115
0.17
1
1113 - AAC - SING
495
KERCKHOFF
CLOVIS-SANGER #1
115
115
37.05
1
715.5 - AAC - SIN
496
KERCKHOFF
CLOVIS-SANGER #2
115
115
32.05
1
715.5 - AAC - SIN
497
KERCKHOFF #1
KERCKHOFF #2
115
115
1.58
1
AAC - SINGLE 266.
498
(cn)
KERN
KERN FRONT
115
115
12.52
1
715.5 - AAC - SIN
499
KERN
TEVIS-STOCKDALE-LAMONT
115
115
21.52
1
715.5 - AAC - SIN
500
KERN
LIVE OAK
115
115
10.74
1
715.5 - AAC - SIN
501
KERN
MAGUNDEN-WITCO
115
115
19.58
1
715.5 - AAC - SIN
502
KERN
ROSEDALE
115
115
1.71
1
715.5 - AAC - SIN
503
KERN
TEVIS-STOCKDALE
115
115
19.74
1
715.5 - AAC - SIN
504
(co)
KERN
TEVIS-STOCKDALE (21KV)
115
115
0.67
1
715.5 - AAC - SIN
505
KERN
WESTPARK #1
115
115
3.84
1
715.5 - AAC - SIN
506
KERN
WESTPARK #2
115
115
3.83
1
715.5 - AAC - SIN
507
KERN OIL
DEXZEL
115
115
0.44
1
715.5 - AAC - SIN
508
KERN OIL
WITCO
115
115
4.2
1
715.5 - AAC - SIN
509
KERNWATER TAP
115
115
0.67
1
4/0 - AAC - SINGL
510
KIFER
FMC
115
115
6.01
1
715.5 - AAC - SIN
511
KIFER
FMC
115
115
1.11
1
512
KINGS RIVER
SANGER-REEDLEY
115
115
43.35
1
715.5 - AAC - SIN
513
KINGSBURG
CORCORAN #1
115
115
27.16
1
715.5 - AAC - SIN
514
KINGSBURG
WAUKENA SW STA
115
115
24.94
1
715.5 - AAC - SIN
515
KINGSBURG COGEN TAP
115
115
1.22
1
397.5 - AAC - SIN
516
KM GREEN TAP
115
115
0.2
1
397.5 - ACSR - SI
517
KYOHO TAP
115
115
2.2
1
397.5 - AAC - SIN
518
LAKEVILLE
SONOMA #1
115
115
6.68
1
477 - ACSS - SING
519
LAKEVILLE
SONOMA #2
115
115
7.18
1
477 - ACSS - SING
520
LAKEVILLE
SONOMA #1
115
115
0.55
1
2500 KCMIL - CU
521
LAKEWOOD
MEADOW LANE-CLAYTON
115
115
9.55
1
715.5 - AAC - SIN
522
LAKEWOOD
CLAYTON
115
115
5.52
1
477 - ACSS - SING
523
LAMMERS
KASSON
115
115
8.23
1
477 - ACSS - SING
524
LAMONT
GRIMMWAY MALAGA
115
115
3.55
1
4/0 - AAC - SINGL
525
LAS PALMAS TAP
115
115
0.85
1
4/0 - AAC - SINGL
526
LAS PLUMAS TAP
115
115
0.48
1
1113 - AAC - SING
527
LAWRENCE
MONTA VISTA
115
115
9.44
1
250 - CU - SINGLE
528
LAWRENCE LIVERMORE LAB #1 T
115
115
9
1
954 - ACSS - SING
529
LAWRENCE LIVERMORE LAB #2 T
115
115
9.41
1
2/0 - CU - SINGLE
530
LE GRAND
DAIRYLAND
115
115
11.4
1
715.5 - AAC - SIN
531
LE GRAND
CHOWCHILLA
115
115
10.94
1
1113 - AAC - SING
532
LEPRINO FOODS
LEPRINO SW STA
115
115
6.41
1
715.5 - AAC - SIN
533
LEPRINO FOODS (TRACY) TAP
115
115
0.02
1
4/0 - AAC - SINGL
534
LEPRINO SW STA
HENRIETTA PV
115
115
0.06
1
1113 - AAC - SING
535
LEPRINO SW STA
GWF HANFORD SW STA
115
115
12.38
1
1113 - AAC - SING
536
LERDO
KERN OIL-7TH STANDARD
115
115
16.35
1
715.5 - AAC - SIN
537
LERDO
FAMOSO
115
115
13.45
1
715.5 - AAC - SIN
538
LINCOLN
PLEASANT GROVE
115
115
7.38
1
715.5 - AAC - SIN
539
LINDE TAP
115
115
0.62
1
397.5 - AAC - SIN
540
LIVE OAK
KERN OIL
115
115
4.4
1
715.5 - AAC - SIN
541
LIVE OAK TAP
115
115
3.97
1
715.5 - AAC - SIN
542
(cp)
LLAGAS
GILROY FOODS
115
115
1.98
1
715.5 - AAC - BUN
543
LLAGAS
HOLLISTER
115
115
21.56
1
3/0 - CU - SINGLE
544
LOCKHEED #1 TAP
115
115
1.72
1
397.5 - AAC - SIN
545
LOCKHEED #2 TAP
115
115
1.28
1
397.5 - AAC - SIN
546
LOS ESTEROS
MONTAGUE
115
115
4.64
1
795 - ACSS - SING
547
LOS ESTEROS
TRIMBLE
115
115
3.73
1
795 - ACSS - SING
548
LOS ESTEROS
AGNEW
115
115
1.37
1
715.5 - AAC - SIN
549
(cq)
LOS ESTEROS
NORTECH
115
115
1.98
1
715.5 - AAC - BUN
550
LOWER LAKE
HOMESTAKE
115
115
16.12
1
4/0 - AAC - SINGL
551
LUCERNE #1 TAP
115
115
0.23
1
4/0 - ACSR - SING
552
LUCERNE #2 TAP
115
115
0.23
1
4/0 - ACSR - SING
553
MABURY TAP
115
115
2.81
1
715.5 - AAC - SIN
554
MADISON
VACA
115
115
22.99
1
3/0 - CU - SINGLE
555
MALAGA
KRCD
115
115
0.99
1
1113 - AAC - SING
556
MANCHESTER
AIRWAYS-SANGER
115
115
15.07
1
1431 - AAC - SING
557
MANTECA
VIERRA
115
115
3.98
1
477 - ACSS - SING
558
MANVILLE TAP
115
115
5.54
1
715.5 - AAC - SIN
559
MARTIN
DALY CITY #1
115
115
3.93
1
397.5 - AAC - SIN
560
MARTIN
DALY CITY #2
115
115
3.93
1
397.5 - AAC - SIN
561
MARTIN
EAST GRAND
115
115
3.96
1
477 - ACSS - SING
562
MARTIN
MILLBRAE #1
115
115
7.28
1
477 - ACSS - SING
563
MARTIN
SF AIRPORT
115
115
5.43
1
477 - ACSS - SING
564
MARTIN
MILLBRAE #1
115
115
0.22
1
3000 KCMIL - ALUM
565
MARTIN
SF AIRPORT
115
115
0.23
1
3000 KCMIL - ALUM
566
MARTINEZ
SHELL OIL #1
115
115
0.04
1
715.5 - AAC - SIN
567
MARTINEZ
SHELL OIL #2
115
115
0.06
1
715.5 - AAC - SIN
568
MARTINEZ
SOBRANTE
115
115
16.4
1
715.5 - AAC - SIN
569
MCCALL
KINGSBURG #1
115
115
11.65
1
715.5 - AAC - SIN
570
MCCALL
KINGSBURG #2
115
115
11.57
1
715.5 - AAC - SIN
571
MCCALL
MALAGA
115
115
10.96
1
715.5 - AAC - SIN
572
MCCALL
REEDLEY
115
115
15.2
1
1113 - AAC - SING
573
MCCALL
SANGER #1
115
115
9.23
1
477 - ACSS - SING
574
MCCALL
SANGER #2
115
115
9.2
1
477 - ACSS - SING
575
MCCALL
SANGER #3
115
115
8.3
1
1113 - AAC - SING
576
MCCALL
WEST FRESNO #2
115
115
19.61
1
477 - ACSS - SING
577
MCKEE
PIERCY
115
115
7.75
1
477 - ACSS - SING
578
MELONES
CURTIS
115
115
14.8
1
715.5 - AAC - SIN
579
MELONES
RACETRACK
115
115
10.2
1
397.5 - AAC - SIN
580
MENDOCINO
REDBUD
115
115
34.83
1
397.5 - ACSR - SI
581
MENDOCINO
UKIAH
115
115
9.83
1
715.5 - AAC - SIN
582
MENDOTA
NORTH STAR SOLAR
115
115
0.03
1
397.5 - AAC - SIN
583
MESA
DIVIDE #1
115
115
14.71
1
715.5 - AAC - SIN
584
MESA
DIVIDE #2
115
115
14.72
1
715.5 - AAC - SIN
585
MESA
SANTA MARIA
115
115
4.36
1
715.5 - AAC - SIN
586
MESA
SISQUOC
115
115
17.6
1
715.5 - AAC - SIN
587
(cr)
METCALF
SALINAS #1
115
115
1.94
1
2/0 - CU - SINGLE
588
(cs)
METCALF
SALINAS #2 (12KV)
115
115
6.8
1
2/0 - CU - SINGLE
589
METCALF
COYOTE PUMPING PLANT
115
115
7.86
1
397.5 - AAC - SIN
590
(ct)
METCALF
EDENVALE #1
115
115
5.73
1
715.5 - AAC - SIN
591
(cu)
METCALF
EDENVALE #2
115
115
5.6
1
715.5 - AAC - SIN
592
METCALF
EL PATIO #1
115
115
14.39
1
477 - ACSS - SING
593
METCALF
EL PATIO #2
115
115
14.4
1
477 - ACSS - SING
594
METCALF
EVERGREEN #1
115
115
10.63
1
715.5 - AAC - SIN
595
METCALF
GREEN VALLEY
115
115
25.28
1
715.5 - AAC - SIN
596
METCALF
MORGAN HILL
115
115
9.72
1
715.5 - AAC - SIN
597
(cv)
METCALF
HICKS 1 & 2
115
115
6.62
1
1 - UNKNOWN - UNK
598
MIDSET TAP
115
115
0.72
1
715.5 - AAC - SIN
599
MIDSUN
MIDWAY
115
115
18.86
1
715.5 - AAC - SIN
600
MIDWAY
RENFRO-TUPMAN
115
115
22.6
1
1113 - AAC - SING
601
MIDWAY
TUPMAN-RIO BRAVO-RENFRO
115
115
26.59
1
266.8 - AAC - SIN
602
MIDWAY
SHAFTER
115
115
13.63
1
715.5 - AAC - SIN
603
MIDWAY
TAFT
115
115
19.33
1
715.5 - AAC - SIN
604
MIDWAY
TEMBLOR
115
115
14.53
1
336.4 - AAC - SIN
605
(cw)
MIDWAY
SANTA MARIA
115
115
46.72
1
606
MILLBRAE
SAN MATEO #1
115
115
4.71
1
477 - ACSS - SING
607
MILLER #1 TAP
115
115
21.26
1
1113 - AAC - SING
608
MILLER #2 TAP
115
115
12.32
1
4/0 - AAC - SINGL
609
MILPITAS
SWIFT
115
115
8.86
1
477 - ACSS - SING
610
MISSION POWER TAP
115
115
1.94
1
397.5 - ACSR - SI
611
MISSOURI FLAT
GOLD HILL #1
115
115
19.73
1
715.5 - AAC - SIN
612
MISSOURI FLAT
GOLD HILL #2
115
115
19.69
1
715.5 - AAC - SIN
613
MOFFETT FIELD TAP
115
115
0.16
1
4/0 - AAC - SINGL
614
MONTA VISTA
WOLFE
115
115
2.72
1
477 - ACSS - SING
615
MONTA VISTA
WOLFE
115
115
1.12
1
CU
616
MONTAGUE
TRIMBLE
115
115
2.07
1
795 - ACSS - SING
617
MONTICELLO PH TAP
115
115
0.62
1
4/0 - AAC - SINGL
618
MORAGA
CLAREMONT #1
115
115
5.28
1
715.5 - AAC - SIN
619
MORAGA
CLAREMONT #2
115
115
5.3
1
715.5 - AAC - SIN
620
MORAGA
OAKLAND #1
115
115
5.04
1
3/0 - CU - SINGLE
621
MORAGA
OAKLAND #2
115
115
5.04
1
3/0 - CU - SINGLE
622
MORAGA
OAKLAND #3
115
115
5.05
1
715.5 - AAC - SIN
623
MORAGA
OAKLAND #4
115
115
5.05
1
715.5 - AAC - SIN
624
MORAGA
OAKLAND J
115
115
17.67
1
715.5 - AAC - SIN
625
MORAGA
SAN LEANDRO #1
115
115
11.14
1
715.5 - AAC - SIN
626
MORAGA
SAN LEANDRO #2
115
115
11.01
1
715.5 - AAC - SIN
627
MORAGA
SAN LEANDRO #3
115
115
11
1
715.5 - AAC - SIN
628
MORAGA
LAKEWOOD
115
115
15.11
1
954 - ACSR - SING
629
MORGAN HILL
LLAGAS
115
115
10.84
1
715.5 - AAC - SIN
630
MORRO BAY
SAN LUIS OBISPO #1
115
115
16.01
1
715.5 - AAC - SIN
631
MORRO BAY
SAN LUIS OBISPO #2
115
115
16.02
1
715.5 - AAC - SIN
632
(cx)
MOSS LANDING
DEL MONTE #1
115
115
23.35
1
715.5 - AAC - SIN
633
(cy)
MOSS LANDING
DEL MONTE #2
115
115
23.38
1
715.5 - AAC - SIN
634
MOSS LANDING
GREEN VALLEY #1
115
115
14.32
1
477 - ACSS - SING
635
MOSS LANDING
GREEN VALLEY #2
115
115
14.46
1
477 - ACSS - SING
636
MOSS LANDING
SALINAS #1
115
115
12
1
477 - ACSS - SING
637
MOSS LANDING
SALINAS #2
115
115
12.11
1
477 - ACSS - SING
638
MOSS LANDING
CRAZY HORSE CANYON #1
115
115
10.62
1
477 - ACSS - SING
639
MOSS LANDING
CRAZY HORSE CANYON #2
115
115
10.61
1
477 - ACSS - SING
640
MTN VIEW
MONTA VISTA
115
115
4.8
1
715.5 - AAC - SIN
641
NEWARK
AMES #1
115
115
8.3
1
715.5 - AAC - SIN
642
NEWARK
AMES #2
115
115
8.28
1
715.5 - AAC - SIN
643
NEWARK
AMES #3
115
115
8.28
1
715.5 - AAC - SIN
644
NEWARK
APPLIED MATERIALS
115
115
11.37
1
477 - ACSS - SING
645
NEWARK
DIXON LANDING
115
115
4.69
1
477 - ACSS - SING
646
NEWARK
FREMONT #1
115
115
3.71
1
477 - ACSS - SING
647
NEWARK
FREMONT #2
115
115
3.75
1
477 - ACSS - SING
648
NEWARK
JARVIS #1
115
115
14.25
1
715.5 - AAC - SIN
649
NEWARK
JARVIS #2
115
115
14.48
1
715.5 - AAC - SIN
650
NEWARK
KIFER
115
115
10.61
1
715.5 - AAC - SIN
651
NEWARK
LAWRENCE
115
115
10.25
1
477 - ACSS - SING
652
NEWARK
LAWRENCE LAB
115
115
12.21
1
3/0 - CU - SINGLE
653
NEWARK
MILPITAS #1
115
115
8.48
1
477 - ACSS - SING
654
NEWARK
MILPITAS #2
115
115
10.3
1
1113 - AAC - SING
655
NEWARK
NUMMI
115
115
4.94
1
4/0 - CU - SINGLE
656
NEWARK
NORTHERN RECEIVING STATION
115
115
8.76
1
715.5 - AAC - SIN
657
NEWARK
NORTHERN RECEIVING STATION
115
115
8.67
1
715.5 - AAC - SIN
658
NEWARK
TRIMBLE
115
115
12.36
1
715.5 - AAC - SIN
659
NEWARK
AMES DISTRIBUTION
115
115
8.25
1
715.5 - AAC - SIN
660
NEWARK
APPLIED MATERIALS
115
115
0.74
1
2500 KCMIL - CU
661
NORTECH
NORTHERN RECEIVING STATION
115
115
2.21
1
795 - ACSS - SING
662
(cz)
NORTH TOWER
MARTINEZ JCT #1 (21KV)
115
115
2.61
1
1 - UNKNOWN - UNK
663
NORTHERN RECEIVING STATION
SCOTT #1
115
115
2.08
1
477 - ACCR - SING
664
NORTHERN RECEIVING STATION
SCOTT #2
115
115
1.98
1
477 - ACSS - SING
665
NOTRE DAME
BUTTE
115
115
2.02
1
715.5 - AAC - SIN
666
OAKHURST TAP
115
115
18.16
1
4/0 - ACSR - SING
667
OAKLAND C
MARITIME
115
115
2.36
1
4/0 - ACSR - SING
668
OAKLAND C
TURBINES
115
115
0.19
1
715.5 - AAC - SIN
669
OAKLAND J
GRANT
115
115
14.81
1
715.5 - AAC - PAR
670
OCEANO
CALLENDER SW STA
115
115
4.22
1
715.5 - AAC - SIN
671
OLEUM
G #1
115
115
11.29
1
715.5 - AAC - SIN
672
OLEUM
G #2
115
115
11.3
1
715.5 - AAC - SIN
673
OLEUM
MARTINEZ
115
115
10.5
1
715.5 - AAC - SIN
674
OLEUM
NORTH TOWER-CHRISTIE
115
115
8.33
1
715.5 - AAC - SIN
675
OLEUM
UNOCAL #1
115
115
0.01
1
250 - CU - SINGLE
676
OLEUM
UNOCAL #2
115
115
0.05
1
715.5 - AAC - SIN
677
OLIVE SW STA
SMYRNA
115
115
22.09
1
1113 - AAC - SING
678
OWENS BROCKWAY TAP
115
115
1.09
1
4/0 - AAC - SINGL
679
OWENS ILLINOIS TAP
115
115
0.68
1
4/0 - AAC - SINGL
680
OXFORD TAP
115
115
3.87
1
4/0 - AAC - SINGL
681
P
X #2
115
115
0.28
1
682
P
X #1
115
115
4.01
1
1000 KCMIL - CU
683
P
X #2 (UNDERGROUND)
115
115
3.95
1
1000 KCMIL - CU
684
PALERMO
BOGUE
115
115
35.74
1
1113 - AAC - SING
685
PALERMO
NICOLAUS
115
115
41.18
1
1113 - AAC - SING
686
PALERMO
PEASE
115
115
26.53
1
715.5 - AAC - SIN
687
PALERMO
WYANDOTTE
115
115
5.3
1
715.5 - AAC - SIN
688
(da)
PANOCHE
CAL PEAK-STARWOOD
115
115
0.1
1
715.5 - AAC - BUN
689
PANOCHE
MENDOTA
115
115
10.08
1
477 - ACSS - SING
690
PANOCHE
ORO LOMA
115
115
18.96
1
477 - ACSS - SING
691
PANOCHE
EXCELSIOR SW STA #1
115
115
28.5
1
715.5 - AAC - SIN
692
PANOCHE
EXCELSIOR SW STA #2
115
115
28.5
1
715.5 - AAC - SIN
693
PARADISE
TABLE MTN
115
115
33.73
1
715.5 - AAC - SIN
694
PARADISE
BUTTE
115
115
13.58
1
715.5 - AAC - SIN
695
PARAMOUNT FARMS TAP
115
115
0.57
1
4/0 - AAC - SINGL
696
PEASE
RIO OSO
115
115
27.61
1
336.4 - ACSR - SI
697
PENNGROVE SUB TAP
115
115
0.81
1
4/0 - AAC - SINGL
698
PEORIA TAP
115
115
0.85
1
397.5 - ACSR - SI
699
PIERCY
METCALF
115
115
4.72
1
477 - ACSS - SING
700
(db)
PITTSBURG
CLAYTON #1
115
115
16.82
1
715.5 - AAC - PAR
701
(dc)
PITTSBURG
CLAYTON #3
115
115
8.41
1
715.5 - AAC - BUN
702
(dd)
PITTSBURG
CLAYTON #4
115
115
8.32
1
715.5 - AAC - BUN
703
PITTSBURG
COLUMBIA STEEL
115
115
9.23
1
715.5 - AAC - SIN
704
(de)
PITTSBURG
LOS MEDANOS #1
115
115
0.54
1
2300 - AAC - BUND
705
(df)
PITTSBURG
LOS MEDANOS #2
115
115
0.54
1
2300 - AAC - BUND
706
PITTSBURG
KIRKER-COLUMBIA STEEL
115
115
9.26
1
715.5 - AAC - SIN
707
PITTSBURG
MARTINEZ #1
115
115
17.22
1
477 - ACSS - SING
708
PITTSBURG
MARTINEZ #2
115
115
15.83
1
477 - ACSS - SING
709
PITTSBURG
LOS MEDANOS #1
115
115
0.88
1
3000 KCMIL - CU
710
PITTSBURG
LOS MEDANOS #2
115
115
0.89
1
3000 KCMIL - CU
711
PLACER
GOLD HILL #1
115
115
20.67
1
2300 - AAC - SING
712
PLACER
GOLD HILL #2
115
115
20.67
1
2300 - AAC - SING
713
POINT PINOLE TAP
115
115
1.3
1
715.5 - AAC - SIN
714
POST OFFICE TAP
115
115
0.75
1
4/0 - AAC - SINGL
715
PSE MCKITTRICK TAP
115
115
5.21
1
715.5 - AAC - SIN
716
QUEBEC TAP
115
115
4.35
1
4/0 - AAC - SINGL
717
RACETRACK TAP
115
115
3.55
1
397.5 - AAC - SIN
718
RAINBOW TAP
115
115
2.59
1
715.5 - AAC - SIN
719
RANCHERS COTTON TAP
115
115
2.1
1
397.5 - AAC - SIN
720
RAVENSWOOD
AMES #1
115
115
7.07
1
477 - ACSS - SING
721
RAVENSWOOD
AMES #2
115
115
7.09
1
477 - ACSS - SING
722
RAVENSWOOD
BAIR #1
115
115
7.43
1
715.5 - AAC - SIN
723
RAVENSWOOD
BAIR #2
115
115
11.29
1
715.5 - AAC - SIN
724
RAVENSWOOD
COOLEY LANDING #1
115
115
1.62
1
715.5 - AAC - SIN
725
RAVENSWOOD
COOLEY LANDING #2
115
115
1.62
1
715.5 - AAC - SIN
726
RAVENSWOOD
PALO ALTO #1
115
115
4.28
1
715.5 - AAC - SIN
727
RAVENSWOOD
PALO ALTO #2
115
115
4.26
1
715.5 - AAC - SIN
728
RAVENSWOOD
SAN MATEO
115
115
12.04
1
715.5 - AAC - SIN
729
RINCON #1 TAP
115
115
0.57
1
397.5 - AAC - SIN
730
RINCON #2 TAP
115
115
0.55
1
397.5 - AAC - SIN
731
(dg)
RIO BRAVO
KERN OIL
115
115
7.28
1
266.8 - AAC - SIN
732
RIO BRAVO (FRESNO) TAP
115
115
0.32
1
4/0 - AAC - SINGL
733
RIO BRAVO (ROCKLIN) TAP
115
115
0.4
1
4/0 - AAC - SINGL
734
RIO BRAVO TOMATO TAP
115
115
0.43
1
1113 - AAC - SING
735
RIO OSO
LINCOLN
115
115
11.02
1
1113 - AAC - SING
736
RIO OSO
NICOLAUS
115
115
5.39
1
1113 - AAC - SING
737
RIO OSO
WEST SACRAMENTO
115
115
43.56
1
336.4 - ACSR - SI
738
RIO OSO
WOODLAND #1
115
115
45.25
1
715.5 - AAC - SIN
739
RIO OSO
WOODLAND #2
115
115
53.37
1
715.5 - AAC - SIN
740
RIPON TAP
115
115
4.64
1
397.5 - AAC - SIN
741
RIVERBANK JCT SW STA
MANTECA
115
115
17.65
1
4/0 - ACSR - SING
742
SAFEWAY TAP
115
115
0.68
1
477 - ACSS - SING
743
SALT SPRINGS
TIGER CREEK
115
115
16.48
1
4/0 - CU - SINGLE
744
SAN BENITO
HOLLISTER
115
115
8.31
1
477 - ACSS - SING
745
(dh)
SAN FRANCISCO #2
115
115
3.15
1
1 - UNKNOWN - UNK
746
SAN JOAQUIN COGEN TAP
115
115
0.04
1
715.5 - AAC - SIN
747
SAN JOSE A
SAN JOSE B
115
115
1.15
1
1113 - AAC - SING
748
SAN JOSE B
STONE-EVERGREEN
115
115
8.56
1
1113 - AAC - SING
749
SAN LEANDRO
OAKLND J #1
115
115
6.7
1
715.5 - AAC - SIN
750
SAN LUIS #3 TAP
115
115
16.11
1
397.5 - ACSR - SI
751
SAN LUIS #5 TAP
115
115
1.88
1
397.5 - ACSR - SI
752
SAN LUIS OBISPO
OCEANO
115
115
19.9
1
715.5 - AAC - SIN
753
SAN LUIS OBISPO
SANTA MARIA
115
115
25.96
1
336.4 - AAC - SIN
754
SAN MATEO
BAY MEADOWS #1
115
115
4.3
1
4/0 - CU - SINGLE
755
SAN MATEO
BAY MEADOWS #2
115
115
4.26
1
4/0 - CU - SINGLE
756
SAN MATEO
BELMONT
115
115
7.2
1
715.5 - AAC - SIN
757
SAN MATEO
MARTIN #3
115
115
11.55
1
477 - ACSS - SING
758
SAN MATEO
MARTIN #6
115
115
11.68
1
477 - ACSS - SING
759
SAN MATEO
MARTIN #4
115
115
11.64
1
477 - ACSS - SING
760
SAN MATEO
MARTIN #4
115
115
0.21
1
3000 KCMIL - ALUM
761
SAN MATEO
MARTIN #3
115
115
0.21
1
3000 KCMIL - ALUM
762
SAN MATEO
MARTIN #6
115
115
0.23
1
3000 KCMIL - ALUM
763
SAN PABLO #1 TAP
115
115
0.44
1
715.5 - AAC - SIN
764
SAN PABLO #2 TAP
115
115
0.45
1
715.5 - AAC - SIN
765
SANDBAR TAP
115
115
0.09
1
397.5 - ACSR - SI
766
SANGER
MALAGA
115
115
8.82
1
715.5 - AAC - SIN
767
SANGER
CALIFORNIA AVE
115
115
9.33
1
1113 - AAC - SING
768
SANGER
REEDLEY
115
115
20.42
1
1113 - AAC - SING
769
SANGER COGEN TAP
115
115
0.83
1
715.5 - AAC - SIN
770
SANTA MARIA
SISQUOC
115
115
10.57
1
715.5 - AAC - SIN
771
SANTA MARIA COGEN TAP
115
115
0.24
1
397.5 - AAC - SIN
772
SANTA PAULA
MILLBRAE
115
115
0.09
1
397.5 - AAC - SIN
773
SANTA ROSA
CORONA
115
115
14.39
1
477 - ACSS - SING
774
SANTA YNEZ TAP
115
115
4.06
1
397.5 - AAC - SIN
775
(di)
SARGENT SW STA
HOLLISTER
115
115
1.54
1
1 - UNKNOWN - UNK
776
SCHULTE SW STA
LAMMERS
115
115
0.69
1
954 - ACSS - SING
777
SCHULTE SW STA
KASSON-MANTECA
115
115
16.56
1
477 - ACSS - SING
778
SEMITROPIC
CHARCA
115
115
6.91
1
397.5 - AAC - SIN
779
SEMITROPIC
MIDWAY #1
115
115
14.1
1
1113 - AAC - SING
780
SEMITROPIC
MIDWAY #2
115
115
20.11
1
715.5 - AAC - SIN
781
SERRAMONTE TAP
115
115
2.55
1
397.5 - AAC - SIN
782
SF AIRPORT
SAN MATEO
115
115
6.09
1
477 - ACSS - SING
783
SHAFTER
RIO BRAVO
115
115
8.31
1
715.5 - AAC - SIN
784
SHARON PRISON TAP
115
115
2.57
1
4/0 - AAC - SINGL
785
SHREDDER TAP
115
115
1.38
1
2/0 - CU - SINGLE
786
(dj)
SIERRA #1
115
115
5.47
1
4/0 - CU - SINGLE
787
(dk)
SIERRA #2
115
115
4.86
1
4/0 - CU - SINGLE
788
SIERRA (PSE) TAP
115
115
1.81
1
715.5 - AAC - SIN
789
SIERRA PACIFIC IND TAP
115
115
0.06
1
4/0 - AAC - SINGL
790
SILVERADO
FULTON JCT
115
115
26.16
1
4/0 - CU - SINGLE
791
SISQUOC
GAREY
115
115
5.02
1
397.5 - AAC - SIN
792
SISQUOC
SANTA YNEZ SW STA
115
115
22.12
1
715.5 - AAC - SIN
793
SKAGGS ISLAND #1 TAP
115
115
0.59
1
4/0 - AAC - SINGL
794
SKAGGS ISLAND #2 TAP
115
115
0.6
1
4/0 - AAC - SINGL
795
SLY CREEK TAP
115
115
5.34
1
4/0 - ACSR - SING
796
SMYRNA
SEMITROPIC-MIDWAY
115
115
44.65
1
266.8 - AAC - SIN
797
(dl)
SOBRANTE
G #1
115
115
5.34
1
715.5 - AAC - SIN
798
SOBRANTE
G #2
115
115
5.39
1
715.5 - AAC - SIN
799
SOBRANTE
GRIZZLY-CLAREMONT #1
115
115
19.58
1
715.5 - AAC - SIN
800
SOBRANTE
MORAGA
115
115
5.68
1
1113 - AAC - SING
801
SOBRANTE
GRIZZLY-CLAREMONT #2
115
115
19.3
1
715.5 - AAC - SIN
802
SOBRANTE
R #1
115
115
5.54
1
715.5 - AAC - SIN
803
SOBRANTE
R #2
115
115
5.53
1
715.5 - AAC - SIN
804
SOBRANTE
STANDARD OIL SW STA #2
115
115
18.89
1
715.5 - AAC - SIN
805
SOBRANTE
STANDARD OIL SW STA #1
115
115
18.89
1
715.5 - AAC - SIN
806
SOBRANTE
R #1
115
115
4.16
1
3000 KCMIL - ALUM
807
SOBRANTE
R #2
115
115
4.11
1
808
SONOMA
PUEBLO
115
115
18.48
1
715.5 - AAC - SIN
809
SPRING GAP TAP
115
115
1.64
1
397.5 - ACSR - SI
810
STANISLAUS
MANTECA #2
115
115
53.95
1
715.5 - AAC - SIN
811
STANISLAUS
MELONES SW STA-MANTECA #1
115
115
61.15
1
715.5 - AAC - SIN
812
STANISLAUS
MELONES SW STA-RIVERBANK JC
115
115
43.8
1
715.5 - AAC - SIN
813
(dm)
STANISLAUS
NEWARK #1 (12KV)
115
115
15.05
1
2/0 - CU - SINGLE
814
(dn)
STANISLAUS
NEWARK #2 (12KV)
115
115
18.17
1
2/0 - CU - SINGLE
815
STELLING
MONTA VISTA
115
115
1.61
1
477 - ACSS - SING
816
STELLING
WOLFE
115
115
1.46
1
477 - ACSS - SING
817
STELLING
MONTA VISTA
115
115
1.14
1
CU
818
STOCKTON A
LOCKEFORD-BELLOTA #1
115
115
34.77
1
715.5 - AAC - SIN
819
STOCKTON A
LOCKEFORD-BELLOTA #2
115
115
34.49
1
715.5 - AAC - SIN
820
STONE
EVERGREEN-METCALF
115
115
12.86
1
715.5 - AAC - SIN
821
STONY POINT TAP
115
115
3.08
1
397.5 - AAC - SIN
822
SURF TAP
115
115
11.38
1
397.5 - AAC - SIN
823
SWIFT
METCALF
115
115
8.93
1
477 - ACSS - SING
824
SYCAMORE CREEK
NOTRE DAME-TABLE MTN
115
115
20.33
1
715.5 - AAC - SIN
825
TABLE MTN
BUTTE #1
115
115
19.54
1
715.5 - AAC - SIN
826
TABLE MTN
BUTTE #2
115
115
15.82
1
715.5 - AAC - SIN
827
TAFT
CHALK CLIFF
115
115
7.18
1
715.5 - AAC - SIN
828
TEICHERT TAP
115
115
2.11
1
4/0 - AAC - SINGL
829
TEMBLOR
KERNRIDGE
115
115
4.78
1
715.5 - AAC - SIN
830
TEMBLOR
SAN LUIS OBISPO
115
115
57.79
1
715.5 - AAC - SIN
831
TESLA
SCHULTE SW STA #2
115
115
7.34
1
715.5 - AAC - SIN
832
TESLA
SCHULTE SW STA #1
115
115
7.39
1
715.5 - AAC - SIN
833
TESLA
SALADO #1
115
115
32.07
1
715.5 - AAC - SIN
834
TESLA
SALADO-MANTECA
115
115
53.96
1
715.5 - AAC - SIN
835
(do)
TESLA
STOCKTON COGEN JCT
115
115
44.47
1
715.5 - AAC - SIN
836
TESLA
TRACY
115
115
25.23
1
1113 - AAC - SING
837
THERMAL ENERGY TAP
115
115
0.74
1
715.5 - AAC - SIN
838
TRIMBLE
SAN JOSE B
115
115
2.53
1
715.5 - AAC - SIN
839
TRIMBLE
SAN JOSE B
115
115
1.11
1
840
TRINITY
COTTONWOOD
115
115
45.97
1
336.4 - ACAR - SI
841
TULLOCH TAP
115
115
0.31
1
397.5 - AAC - SIN
842
TUPMAN-NORCO TAP
115
115
6.67
1
715.5 - AAC - SIN
843
UC DAVIS #1 TAP
115
115
1.64
1
715.5 - AAC - SIN
844
UC DAVIS #2 TAP
115
115
1.61
1
715.5 - AAC - SIN
845
UKIAH
HOPLAND-CLOVERDALE
115
115
31.17
1
715.5 - AAC - SIN
846
ULTRAPOWER (OGLE) TAP
115
115
2.45
1
1113 - AAC - SING
847
UNION OIL TAP
115
115
0.5
1
4/0 - AAC - SINGL
848
UNITED COGEN INC TAP
115
115
0.68
1
397.5 - AAC - SIN
849
UNIVERSITY COGEN TAP
115
115
0.22
1
715.5 - AAC - SIN
850
VACA
SUISUN
115
115
23.06
1
715.5 - AAC - SIN
851
VACA
SUISUN-JAMESON
115
115
25.46
1
715.5 - AAC - SIN
852
VACA
VACAVILLE-CORDELIA
115
115
22.04
1
715.5 - AAC - SIN
853
VACA
VACAVILLE-JAMESON-NORTH TOW
115
115
36.18
1
715.5 - AAC - SIN
854
VALLEY CHILDRENS HOSPITAL T
115
115
0.03
1
4/0 - AAC - SINGL
855
VALLEY VIEW #1 TAP
115
115
0.96
1
715.5 - AAC - SIN
856
VALLEY VIEW #2 TAP
115
115
0.97
1
715.5 - AAC - SIN
857
(dp)
VEDDER TAP
115
115
11.09
1
3/0 - AAC - SINGL
858
VIERRA
TRACY-KASSON
115
115
10.49
1
715.5 - AAC - SIN
859
WASCO PRISON TAP
115
115
0.54
1
4/0 - AAC - SINGL
860
WAUKENA SW STA
CORCORAN
115
115
2.37
1
1113 - AAC - SING
861
WEST FRESNO
CALIFORNIA AVE
115
115
4.9
1
715.5 - AAC - SIN
862
WEST SACRAMENTO
BRIGHTON
115
115
13.97
1
477 - ACSS - SING
863
WEST SACRAMENTO
DAVIS
115
115
12.14
1
715.5 - AAC - SIN
864
WESTLANDS #1 RA PUMPING PLA
115
115
1.05
1
4/0 - AAC - SINGL
865
WESTLANDS #18 RA TAP
115
115
3.52
1
4/0 - AAC - SINGL
866
WESTPARK
MAGUNDEN
115
115
12.29
1
715.5 - AAC - SIN
867
WHEELER RIDGE
ADOBE SW STA
115
115
1.34
1
715.5 - AAC - SIN
868
WHISMAN
MONTA VISTA
115
115
5.97
1
715.5 - AAC - SIN
869
WHISMAN
MTN VIEW
115
115
3.54
1
715.5 - AAC - SIN
870
(dq)
WILSON
DAIRYLAND (12KV)
115
115
11.37
1
266.8 - AAC - SIN
871
WILSON
ATWATER #2
115
115
15.41
1
715.5 - AAC - SIN
872
WILSON
LE GRAND
115
115
14.04
1
715.5 - AAC - SIN
873
WILSON
MERCED #1
115
115
5.58
1
715.5 - AAC - SIN
874
WILSON
MERCED #2
115
115
6.2
1
266.8 - AAC - SIN
875
WILSON
ORO LOMA
115
115
43.56
1
715.5 - AAC - SIN
876
WITCO (REFINERY) TAP
115
115
0.03
1
4/0 - AAC - SINGL
877
WOODLAND
DAVIS
115
115
11.71
1
715.5 - AAC - SIN
878
WOODLAND BIOMASS TAP
115
115
0.87
1
4/0 - AAC - SINGL
879
WOODLEAF
PALERMO
115
115
19.62
1
715.5 - AAC - SIN
880
WOODWARD
SHEPHERD
115
115
4.84
1
2300 - AAC - SING
881
X
Y #1
115
115
0.57
1
1250 KCMIL - CU
882
ZAMORA TAP
115
115
1.92
1
397.5 - AAC - SIN
883
ZANKER #1 TAP
115
115
0.6
1
715.5 - AAC - SIN
884
ZANKER #2 TAP
115
115
0.72
1
4/0 - AAC - SINGL
885
(dr)
AERA ENERGY TAP
70
60
0.35
1
397.5 - ALUM - SI
886
ANTELOPE TAP
70
70
4.33
1
4/0 - AAC - SINGL
887
ARBURUA TAP
70
70
3.57
1
2 - ACSR - SINGLE
888
ARCO
CARNERAS
70
70
17.97
1
715.5 - AAC - SIN
889
ARCO
CHOLAME
70
70
26.74
1
397.5 - AAC - SIN
890
ARCO
POLONIO PASS PP
70
70
21.27
1
715.5 - AAC - SIN
891
ARCO
TULARE LAKE
70
70
16.11
1
3/0 - AAC - SINGL
892
ARCO
TWISSELMAN
70
70
6.52
1
715.5 - AAC - SIN
893
ARMSTRONG TAP
70
70
0.44
1
4/0 - AAC - SINGL
894
ATASCADERO
CAYUCOS
70
70
11.8
1
3/0 - AAC - SINGL
895
ATASCADERO
SAN LUIS OBISPO
70
70
15.47
1
715.5 - AAC - SIN
896
AUBERRY TAP
70
70
2.27
1
1/0 - ACSR - SING
897
AVENAL TAP
70
70
5.4
1
397.5 - AAC - SIN
898
BADGER HILL TAP
70
70
1.56
1
1/0 - ACSR - SING
899
BERRENDA A TAP
70
70
2.25
1
4/0 - AAC - SINGL
900
BERRENDA C TAP
70
70
1.87
1
4/0 - AAC - SINGL
901
BIOLA
GLASS-MADERA
70
70
18.84
1
715.5 - AAC - SIN
902
BONITA TAP
70
70
3.04
1
2 - CU - SINGLE
903
BORDEN
COPPERMINE
70
70
19.95
1
4/0 - CU - SINGLE
904
BORDEN
GLASS
70
70
6.62
1
715.5 - AAC - SIN
905
BORDEN
MADERA #2
70
70
5.81
1
715.5 - AAC - SIN
906
BORDEN
MADERA #1
70
70
4.91
1
715.5 - AAC - SIN
907
BORDEN
GLASS; XLPE; 70 KV
70
70
0.39
1
1750 KCMIL - ALUM
908
BOSWELL TAP
70
70
1.39
1
4/0 - ACSR - SING
909
BRICEBURG JCT-MARIPOSA TAP
70
70
7.78
1
715.5 - AAC - SIN
910
CADET TAP
70
70
0.12
1
397.5 - AAC - SIN
911
CALIFORNIA AVE
KEARNEY
70
70
3.2
1
715.5 - AAC - SIN
912
CAMDEN
KINGSBURG
70
70
14.91
1
266.8 - AAC - SIN
913
CANANDAIGUA WINERY TAP
70
70
0.29
1
4/0 - AAC - SINGL
914
CARNATION TAP
70
70
0.61
1
4/0 - AAC - SINGL
915
CARNERAS
TAFT
70
70
34.92
1
3/0 - AAC - SINGL
916
CARUTHERS
LEMOORE NAS-CAMDEN
70
70
25.17
1
3/0 - AAC - SINGL
917
CASTAIC TAP
70
70
0.02
1
2 - ACSR - SINGLE
918
CAWELO B TAP
70
70
0.4
1
4/0 - AAC - SINGL
919
CAYUCOS
CAMBRIA
70
70
17.73
1
307.1 - AAC - SIN
920
CELERON TAP
70
70
0.04
1
4/0 - AAC - SINGL
921
CHEVRON (LOST HILLS) TAP
70
70
14.75
1
397.5 - AAC - SIN
922
CHEVRON PIPELINE KETTLEMAN
70
70
1.17
1
4/0 - AAC - SINGL
923
COALINGA #1
COALINGA #2
70
70
8.61
1
1113 - AAC - SING
924
COALINGA #1
SAN MIGUEL
70
70
38.01
1
266.8 - ACSR - SI
925
COALINGA COGEN TAP
70
70
4.91
1
715.5 - AAC - SIN
926
COPPERMINE
TIVY VALLEY
70
70
24.01
1
715.5 - AAC - SIN
927
COPUS
OLD RIVER
70
70
19.61
1
715.5 - AAC - SIN
928
CORCORAN
ANGIOLA
70
70
8.96
1
4/0 - CU - SINGLE
929
CORCORAN
GUERNSEY
70
70
13.57
1
1113 - AAC - SING
930
CRESCENT SW STA
SCULPIN PV
70
0.04
1
1113 - AAC - SING
931
CRESCENT SW STA
SCHINDLER
70
70
10.8
1
1113 - AAC - SING
932
CRESCENT SW STA
STROUD
70
70
3.61
1
1113 - AAC - SING
933
DERRICK TAP
70
70
0.85
1
397.5 - AAC - SIN
934
DINOSAUR POINT TAP
70
70
2
1
2/0 - CU - SINGLE
935
DINUBA
OROSI
70
70
9.83
1
715.5 - AAC - SIN
936
DINUBA ENERGY TAP
70
70
3.16
1
397.5 - AAC - SIN
937
DIVIDE
VANDENBERG #1
70
70
6.64
1
266.8 - AAC - SIN
938
DIVIDE
VANDENBERG #2
70
70
6.57
1
715.5 - AAC - SIN
939
(ds)
DIVIDE
ZACA-LOMPOC (12KV)
70
70
10.55
1
397.5 - AAC - SIN
940
DUNLAP TAP
70
70
16.21
1
715.5 - AAC - SIN
941
EISEN TAP
70
70
1.86
1
1/0 - ACSR - SING
942
EL PECO TAP
70
70
3.02
1
397.5 - AAC - SIN
943
EMIDIO TAP
70
70
3.07
1
1/0 - ACSR - SING
944
EXCHEQUER
MARIPOSA
70
70
19.3
1
715.5 - AAC - SIN
945
EXCHEQUER
YOSEMITE
70
70
34.91
1
3/0 - ACSR - SING
946
FIVE POINTS SW
WHITNEY POINT PV
70
70
0.06
1
715.5 - AAC - SIN
947
FIVE POINTS SW STA
HURON-GATES
70
70
19.78
1
715.5 - AAC - SIN
948
FRESNO COGEN (AGRICO) TAP
70
70
3.17
1
715.5 - AAC - SIN
949
FRIANT
COPPERMINE
70
70
8.3
1
715.5 - AAC - SIN
950
FRUITVALE TAP
70
70
0.12
1
4/0 - CU - SINGLE
951
GARDNER TAP
70
70
3.77
1
4/0 - AAC - SINGL
952
GATES
JAYNE SW STA
70
70
0.68
1
715.5 - AAC - SIN
953
GATES
COALINGA #2
70
70
17.26
1
715.5 - AAC - SIN
954
GATES
HURON
70
70
4.5
1
715.5 - AAC - SIN
955
GATES
TULARE LAKE
70
70
18.34
1
715.5 - AAC - SIN
956
GIFFEN TAP
70
70
4.95
1
1113 - AAC - SING
957
GRAPEVINE TAP
70
70
0.14
1
1/0 - ACSR - SING
958
GUERNSEY
HENRIETTA
70
70
18.44
1
266.8 - AAC - SIN
959
GWF
HENRIETTA
70
70
0.12
1
477 - ACSS - SING
960
GWF HANFORD COGEN TAP
70
70
0.32
1
397.5 - AAC - SIN
961
HAAS
WOODCHUCK
70
70
6.79
1
4/0 - ACSR - SING
962
HARDWICK TAP
70
70
2.74
1
266.8 - AAC - SIN
963
HELM
KERMAN
70
70
13.25
1
715.5 - AAC - SIN
964
HELM
CRESCENT SW STA
70
70
4.92
1
715.5 - AAC - SIN
965
HELM
STROUD
70
70
7.43
1
715.5 - AAC - SIN
966
HENRIETTA
LEMOORE
70
70
9.37
1
715.5 - AAC - SIN
967
HENRIETTA
LEMOORE NAS
70
70
1.69
1
715.5 - AAC - SIN
968
HENRIETTA
KENT SW STA
70
70
1.47
1
715.5 - AAC - SIN
969
HERDLYN
TRACY
70
70
2.06
1
715.5 - AAC - SIN
970
JAYNE SW STA
COALINGA
70
70
11.81
1
715.5 - AAC - SIN
971
KEARNEY
BIOLA
70
70
19.13
1
4/0 - CU - SINGLE
972
KEARNEY
BOWLES
70
70
9.29
1
4/0 - AAC - SINGL
973
KEARNEY
CARUTHERS
70
70
12.05
1
715.5 - AAC - SIN
974
KEARNEY
KERMAN
70
70
10.98
1
715.5 - AAC - SIN
975
KEARNEY ALTERNATE TIE
70
70
0.3
1
1113 - AAC - SING
976
KEARNEY TIE
70
70
0.15
1
1113 - AAC - SING
977
KELLEY TAP
70
70
2.79
1
1/0 - ACSR - SING
978
KENT SW STA
TULARE LAKE
70
70
15.93
1
715.5 - AAC - SIN
979
KERN
FRUITVALE
70
70
0.16
1
397.5 - AAC - SIN
980
KERN
KERN OIL-FAMOSO
70
70
24.69
1
715.5 - AAC - SIN
981
KERN
MAGUNDEN
70
70
20.61
1
715.5 - AAC - SIN
982
KERN
OLD RIVER #1
70
70
11.94
1
795 - ACSS - SING
983
KERN
OLD RIVER #2
70
70
23.07
1
1/0 - CU - SINGLE
984
KERN CANYON
MAGUNDEN-WEEDPATCH
70
70
20.65
1
397.5 - AAC - SIN
985
KETTLEMAN HILLS TAP
70
70
1.02
1
715.5 - AAC - SIN
986
KINGSBURG
LEMOORE
70
70
27.49
1
3/0 - CU - SINGLE
987
LAS PERILLAS TAP
70
70
0.39
1
1/0 - ACSR - SING
988
LEPRINO TAP
70
70
0.47
1
4/0 - AAC - SINGL
989
(dt)
LIGHTNER TAP
70
70
3.06
1
1 - UNKNOWN - UNK
990
LIVINGSTON
LIVINGSTON JCT
70
70
23.36
1
715.5 - AAC - SIN
991
LOS BANOS
MERCY SPRINGS SW STA
70
70
14.73
1
715.5 - AAC - SIN
992
LOS BANOS
LIVINGSTON JCT-CANAL
70
70
14.29
1
715.5 - AAC - SIN
993
LOS BANOS
O'NEILL PGP
70
70
3.88
1
715.5 - AAC - SIN
994
LOS BANOS
PACHECO
70
70
20.78
1
715.5 - AAC - SIN
995
LOST HILLS TAP
70
70
2.89
1
1/0 - ACSR - SING
996
MARICOPA
COPUS
70
70
7.86
1
715.5 - AAC - SIN
997
MCFARLAND TAP
70
70
5.99
1
1/0 - CU - SINGLE
998
MCSWAIN TAP
70
70
1.37
1
4/0 - AAC - SINGL
999
MENDOTA
SAN JOAQUIN-HELM
70
70
26.96
1
715.5 - AAC - SIN
1000
MENDOTA BIOMASS TAP
70
70
3.84
1
397.5 - AAC - SIN
1001
MERCED
MERCED FALLS
70
70
20.93
1
715.5 - AAC - SIN
1002
MERCED #1
70
70
39.88
1
2 - UNKNOWN - SIN
1003
MERCED FALLS
EXCHEQUER
70
70
6.29
1
3/0 - CU - SINGLE
1004
MERCY SPRINGS SW STA
CANAL-ORO LOMA
70
70
23.32
1
715.5 - AAC - SIN
1005
MOCO TAP
70
70
1.64
1
397.5 - AAC - SIN
1006
MUSTANG TAP
70
70
0.71
1
4/0 - AAC - SINGL
1007
OIL CITY TAP
70
70
0.05
1
4/0 - AAC - SINGL
1008
ORO LOMA
CANAL #1
70
70
24.56
1
397.5 - AAC - SIN
1009
ORO LOMA
MENDOTA
70
70
29.58
1
266.8 - AAC - SIN
1010
PASO ROBLES
TEMPLETON
70
70
4.9
1
1113 - AAC - SING
1011
PENN ZIER TAP
70
70
4.99
1
715.5 - AAC - SIN
1012
PENTLAND TAP
70
70
0.55
1
4/0 - AAC - SINGL
1013
REEDLEY
DINUBA #1
70
70
7.7
1
715.5 - AAC - SIN
1014
REEDLEY
OROSI
70
70
10.89
1
715.5 - AAC - SIN
1015
RESERVE OIL TAP
70
70
0.58
1
1/0 - ACSR - SING
1016
RIO BRAVO HYDRO
70
70
0.24
1
4/0 - AAC - SINGL
1017
RIVER ROCK TAP
70
70
1.21
1
4/0 - AAC - SINGL
1018
ROSE TAP
70
70
0.31
1
4/0 - AAC - SINGL
1019
SAN BERNARD
TEJON
70
70
6.96
1
715.5 - AAC - SIN
1020
SAN LUIS OBISPO
CAYUCOS
70
70
23.39
1
715.5 - AAC - SIN
1021
(du)
SAN LUIS OBISPO
SANTA MARIA *
70
70
13.33
1
4/0 - AAC - SINGL
1022
SAN MIGUEL
PASO ROBLES
70
70
9.92
1
4/0 - AAC - SINGL
1023
(dv)
SANGER
CALIFORNIA AVE #1
70
70
9.23
1
266.8 - AAC - SIN
1024
SCHINDLER
COALINGA #2
70
70
17.26
1
715.5 - AAC - SIN
1025
SCHINDLER
FIVE POINTS SW STA
70
70
1.7
1
4/0 - CU - SINGLE
1026
SEMITROPIC
WASCO
70
70
6.32
1
1113 - AAC - SING
1027
SOLAR TANNEHILL TAP
70
70
2.65
1
715.5 - AAC - SIN
1028
STONE CORRAL TAP
70
70
7.56
1
3/0 - AAC - SINGL
1029
SYCAMORE TAP
70
70
2.04
1
4/0 - AAC - SINGL
1030
(dw)
TAFT
CUYAMA #1
70
70
19.25
1
715.5 - AAC - SIN
1031
TAFT
CUYAMA #2
70
70
18.75
1
2 - ACSR - SINGLE
1032
TAFT
ELK HILLS
70
70
12.39
1
4 - CU - SINGLE 4
1033
(dx)
TAFT
MARICOPA
70
70
5.98
1
3/0 - CU - SINGLE
1034
TECUYA TAP
70
70
1.91
1
1/0 - ACSR - SING
1035
TEJON
LEBEC
70
70
13
1
1/0 - ACSR - SING
1036
TEMPLETON
ATASCADERO
70
70
8.82
1
1113 - AAC - SING
1037
TEXACO (LOST HILLS) TAP
70
70
0.01
1
397.5 - AAC - SIN
1038
TEXACO BASIC SCHOOL TAP
70
70
0.75
1
4/0 - AAC - SINGL
1039
TEXACO BUENA VISTA HILLS TA
70
70
0.1
1
4/0 - AAC - SINGL
1040
TIVY VALLEY
REEDLEY
70
70
12.3
1
397.5 - AAC - SIN
1041
TORNADO TAP
70
70
0.06
1
1/0 - ACSR - SING
1042
TULE
SPRINGVILLE
70
70
15.24
1
1/0 - CU - SINGLE
1043
WASCO
FAMOSO
70
70
7.13
1
715.5 - AAC - SIN
1044
WEEDPATCH
SAN BERNARD
70
70
9.29
1
715.5 - AAC - SIN
1045
WEEDPATCH
WELLFIELD
70
70
5.82
1
4/0 - AAC - SINGL
1046
WESIX TAP
70
70
2.51
1
2 - ACSR - SINGLE
1047
WESTLANDS TAP
70
70
1.07
1
1/0 - ACSR - SING
1048
WHEELER RIDGE
LAKEVIEW
70
70
7.51
1
715.5 - AAC - SIN
1049
WHEELER RIDGE
SAN BERNARD
70
70
5.88
1
397.5 - ACSR - SI
1050
WHEELER RIDGE
TEJON
70
70
5.01
1
715.5 - AAC - SIN
1051
WHEELER RIDGE
WEEDPATCH
70
70
22.43
1
3/0 - CU - SINGLE
1052
WISHON
COPPERMINE
70
70
19.99
1
336.4 - AAC - SIN
1053
WISHON
SAN JOAQUIN #3
70
70
7.68
1
1 - CU - SINGLE
1054
WRIGHT TAP
70
70
1.18
1
4/0 - AAC - SINGL
1055
(dy)
YANKE (NORTH FORK) TAP
70
70
0.44
1
397.5 - AAC - SIN
1056
ALMADEN
LOS GATOS
60
60
6.38
1
336.4 - AAC - SIN
1057
ALMENDRA JCT
NICOLAUS
60
60
24.9
1
2/0 - CU - SINGLE
1058
AMFOR TAP
60
60
1.08
1
1/0 - ACSR - SING
1059
ARBUCKLE TAP
60
60
0.82
1
715.5 - AAC - SIN
1060
ARCATA
HUMBOLDT
60
60
7.28
1
715.5 - AAC - SIN
1061
AUBURN TAP
60
60
0.75
1
2/0 - CU - SINGLE
1062
BAIR
COOLEY LANDING #1
60
60
5.55
1
4/0 - CU - SINGLE
1063
BAIR
COOLEY LANDING #2
60
60
5.6
1
715.5 - AAC - SIN
1064
BASALT #1 TAP
60
60
1.18
1
477 - ACSS - SING
1065
BEALE AFB (WAPA) #1 TAP
60
60
0.11
1
2/0 - CU - SINGLE
1066
BEALE AFB (WAPA) #2 TAP
60
60
0.14
1
2/0 - CU - SINGLE
1067
BELLE HAVEN #1 TAP
60
60
0.45
1
477 - ACSS - SING
1068
BELLE HAVEN #2 TAP
60
60
0.4
1
477 - ACSS - SING
1069
BIXLER TAP
60
60
0.55
1
4/0 - AAC - SINGL
1070
BLUE CHIP MILLING TAP
60
60
0.42
1
4/0 - AAC - SINGL
1071
BLUE LAKE TAP
60
60
3.7
1
4/0 - ACAR - SING
1072
BRIDGEVILLE
GARBERVILLE
60
60
36.16
1
4/0 - ACSR - SING
1073
BRIONES TAP
60
60
7
1
4/0 - AAC - SINGL
1074
BUENA VISTA BIOMASS POWER T
60
60
1.02
1
715.5 - AAC - SIN
1075
BURNEY TAP
60
60
1.09
1
1/0 - ACSR - SING
1076
BURNS
LONE STAR #1
60
60
5.42
1
3/0 - CU - SINGLE
1077
BURNS
LONE STAR #2
60
60
6.34
1
3/0 - CU - SINGLE
1078
BUTTE
CHICO #1
60
60
0.79
1
397.5 - AAC - SIN
1079
BUTTE
CHICO #2
60
60
0.74
1
4/0 - AAC - SINGL
1080
(dz)
BUTTE
ESQUON
60
60
9.87
1
4/0 - ALUM - SING
1081
CACHE SLOUGH TAP
60
60
6.85
1
1/0 - ACSR - SING
1082
CALVO TAP
60
60
0.54
1
2 - ACSR - SINGLE
1083
CAPE HORN TAP
60
60
0.31
1
2 - ACSR - SINGLE
1084
CARBONA #2 TAP
60
60
5.64
1
397.5 - AAC - SIN
1085
CARIBOU
PLUMAS JCT
60
60
21.25
1
397.5 - ACSR - SI
1086
CARIBOU
WESTWOOD
60
60
21.06
1
795 - ACSR - SING
1087
CARIBOU #2
60
60
42.12
1
397.5 - ACSR - SI
1088
CASCADE
BENTON-DESCHUTES
60
60
15.98
1
715.5 - AAC - SIN
1089
CENTERVILLE
TABLE MTN
60
60
21.5
1
715.5 - AAC - SIN
1090
CENTERVILLE
TABLE MTN-OROVILLE
60
60
26.11
1
350 - AAC - SINGL
1091
(ea)
CHICO A
DAYTON RD
60
0.8
1
1 - UNKNOWN - UNK
1092
CHRISTIE
FRANKLIN #1
60
60
5.01
1
715.5 - AAC - SIN
1093
CHRISTIE
FRANKLIN #2
60
60
5.11
1
336.4 - AAC - SIN
1094
CHRISTIE
WILLOW PASS
60
60
15.93
1
3/0 - CU - SINGLE
1095
(eb)
CHUALAR TAP
60
60
1.43
1
1 - UNKNOWN - UNK
1096
CIC TAP
60
60
0.13
1
397.5 - AAC - SIN
1097
CISCO GROVE TAP
60
60
0.34
1
2 - ACSR - SINGLE
1098
CLAY
MARTEL
60
60
21.49
1
715.5 - AAC - SIN
1099
CLEAR LAKE
HOPLAND
60
60
11.54
1
4/0 - AAC - SINGL
1100
CLEAR LAKE
KONOCTI
60
60
10.95
1
715.5 - AAC - SIN
1101
CLOVER CREEK TAP
60
60
0.02
1
1102
(ec)
COBURN
BASIC ENERGY
60
60
3.39
1
1431 - AAC - BUND
1103
COBURN
OIL FIELDS #1
60
60
29.46
1
715.5 - AAC - SIN
1104
COBURN
OIL FIELDS #2
60
60
31.05
1
715.5 - AAC - SIN
1105
COGENERATION NATIONAL TAP
60
60
0.56
1
715.5 - AAC - SIN
1106
COLEMAN
COTTONWOOD
60
60
8.58
1
715.5 - AAC - SIN
1107
COLEMAN
RED BLUFF
60
60
48.31
1
1/0 - CU - SINGLE
1108
COLEMAN
SOUTH
60
60
13.39
1
715.5 - AAC - SIN
1109
COLEMAN HATCHERY TAP
60
60
0.56
1
4/0 - AAC - SINGL
1110
COLGATE
ALLEGHANY
60
60
24.55
1
4 - ACSR - SINGLE
1111
COLGATE
CHALLENGE
60
60
13.04
1
4/0 - ACSR - SING
1112
COLGATE
GRASS VALLEY
60
60
13.17
1
2/0 - CU - SINGLE
1113
COLGATE
PALERMO
60
60
22.65
1
715.5 - AAC - SIN
1114
COLGATE
SMARTVILLE #1
60
60
11.26
1
477 - ACSS - SING
1115
COLGATE
SMARTVILLE #2
60
60
11.19
1
4/0 - CU - SINGLE
1116
(ed)
COLGATE PH
COLGATE SW STA
60
60
0.19
1
1113 - AAC - BUND
1117
COLLINS PINE TAP
60
60
1
1
2 - ACSR - SINGLE
1118
COLUSA JCT #1
60
60
16.98
1
715.5 - AAC - SIN
1119
CONTRA COSTA
DU PONT
60
60
2.65
1
715.5 - AAC - SIN
1120
CONTRA COSTA
PITTSBURG
60
60
6.28
1
715.5 - AAC - SIN
1121
(ee)
CONTRA COSTA
SHELL CHEMICAL#1(21KV)
60
60
9.55
1
4/0 - CU - SINGLE
1122
CONTRA COSTA
BALFOUR
60
60
11.55
1
397.5 - AAC - SIN
1123
COOLEY LANDING
LOS ALTOS
60
60
14.89
1
715.5 - AAC - SIN
1124
(ef)
COOLEY LANDING
LOS ALTOS (I2KV)
60
60
1.41
1
715.5 - AAC - SIN
1125
(eg)
COOLEY LANDING
STANFORD
60
60
6.04
1
715.5 - AAC - SIN
1126
COOLEY LANDING
STANFORD
60
60
1.59
1
2000 KCMIL - ALUM
1127
CORDELIA #1 TAP
60
60
7.69
1
1 - CU - SINGLE 2
1128
CORDELIA #2 TAP
60
60
6.87
1
2/0 - CU - SINGLE
1129
CORDELIA INTERIM PUMPING PL
60
60
0.36
1
1/0 - ACSR - SING
1130
CORTINA #1
60
60
26.29
1
715.5 - AAC - SIN
1131
CORTINA #2
60
60
26.61
1
715.5 - AAC - SIN
1132
CORTINA #3
60
60
24.8
1
715.5 - AAC - SIN
1133
CORTINA #4
60
60
45.28
1
715.5 - AAC - SIN
1134
COTTONWOOD
BENTON #1
60
60
15.53
1
715.5 - AAC - SIN
1135
COTTONWOOD
BENTON #2
60
60
14.68
1
250 - CU - SINGLE
1136
COTTONWOOD
RED BLUFF
60
60
16.74
1
300 - AAC - SINGL
1137
COTTONWOOD #1
60
60
48.16
1
4/0 - AAC - SINGL
1138
COTTONWOOD #2
60
60
23.63
1
715.5 - AAC - SIN
1139
CROW CREEK SW STA
FRONTIER SOLAR PV
60
60
0.02
1
715.5 - SINGLE
1140
CROW CREEK SW STA
NEWMAN
60
60
11.14
1
4/0 - CU - SINGLE
1141
CROWS LANDING TAP
60
60
5.28
1
4/0 - CU - SINGLE
1142
CRUSHER TAP
60
60
1.95
1
1/0 - ACSR - SING
1143
CRYSTAL SPRINGS TAP
60
60
0.28
1
4/0 - AAC - SINGL
1144
DEAN FOODS TAP
60
60
0.51
1
397.5 - AAC - SIN
1145
DEER CREEK
DRUM
60
60
6.24
1
2/0 - CU - SINGLE
1146
DEL MAR
ATLANTIC #1
60
60
2.78
1
477 - ACSS - SING
1147
DEL MAR
ATLANTIC #2
60
60
4.45
1
715.5 - AAC - SIN
1148
DEL MAR
ATLANTIC #1
60
60
1.18
1
3000 KCMIL - CU
1149
DEL MONTE
MONTEREY
60
60
2.53
1
715.5 - AAC - SIN
1150
(eh)
DEL MONTE
VIEJO
60
60
7.92
1
715.5 - AAC - SIN
1151
DEL MONTE
FORT ORD #1
60
60
6.13
1
715.5 - AAC - SIN
1152
DEL MONTE
FORT ORD #2
60
60
5.6
1
715.5 - AAC - SIN
1153
DELTA
MTN GATE JCT
60
60
15.14
1
518 - ACSR - SING
1154
DESABLA
CENTERVILLE
60
60
5.86
1
350 - AAC - SINGL
1155
DISTRICT 1001 TAP
60
60
1.47
1
4 - CU - SINGLE
1156
DISTRICT 1500 TAP
60
60
3.61
1
6 - CU - SINGLE 2
1157
DIXON
VACA #1
60
60
18.35
1
715.5 - AAC - SIN
1158
DIXON
VACA #2
60
60
26.77
1
715.5 - AAC - SIN
1159
DRUM
GRASS VALLEY-WEIMAR
60
60
31.17
1
397.5 - ACSR - SI
1160
DRUM
SPAULDING
60
60
9.36
1
4/0 - CU - SINGLE
1161
DU PONT TAP
60
60
0.52
1
715.5 - AAC - SIN
1162
EAST DUBLIN (BART) TAP
60
60
0.04
1
715.5 - AAC - SIN
1163
EEL RIVER TAP
60
60
2.31
1
4/0 - ACSR - SING
1164
ELK
GUALALA
60
60
29.01
1
1/0 - CU - SINGLE
1165
ELK CREEK TAP
60
60
20.44
1
2 - ACSR - SINGLE
1166
ENCINAL TAP
60
60
1.43
1
4 - CU - SINGLE
1167
ESSEX JCT
ARCATA-FAIRHAVEN
60
60
16.08
1
715.5 - AAC - SIN
1168
ESSEX JCT
ORICK
60
60
31.29
1
2/0 - CU - SINGLE
1169
EUREKA
STA A
60
60
0.22
1
715.5 - AAC - SIN
1170
EVERGREEN
ALMADEN
60
60
4.96
1
715.5 - AAC - SIN
1171
EVERGREEN
MABURY
60
60
5.48
1
4/0 - CU - SINGLE
1172
FAIRHAVEN
HUMBOLDT
60
60
15.56
1
715.5 - AAC - SIN
1173
FAIRHAVEN #1
60
60
0.41
1
715.5 - AAC - SIN
1174
FAIRHAVEN POWER CO TAP
60
60
0.55
1
397.5 - AAC - SIN
1175
FITCH MTN #1 TAP
60
60
0.87
1
477 - ACSS - SING
1176
FITCH MTN #2 TAP
60
60
0.07
1
2/0 - CU - SINGLE
1177
FORKS OF THE BUTTE TAP
60
60
0.2
1
350 - AAC - SINGL
1178
FORT BRAGG
ELK
60
60
24.02
1
397.5 - AAC - SIN
1179
FORT ROSS
GUALALA
60
60
29.76
1
715.5 - AAC - SIN
1180
FORT SEWARD TAP
60
60
7.7
1
4/0 - ACSR - SING
1181
FRENCH MEADOWS
MIDDLE FORK
60
60
13.19
1
4/0 - ACSR - SING
1182
FRESH EXPRESS TAP
60
60
0.56
1
2/0 - CU - SINGLE
1183
FRUITLAND TAP
60
60
4.26
1
4/0 - ACSR - SING
1184
FULTON
WINDSOR
60
60
6.59
1
477 - ACSS - SING
1185
FULTON
CALISTOGA
60
60
64.6
1
4/0 - AAC - SINGL
1186
FULTON
HOPLAND
60
60
41.09
1
715.5 - AAC - SIN
1187
FULTON
MOLINO-COTATI
60
60
20.52
1
715.5 - AAC - SIN
1188
(ei)
FULTON
MOLINO-COTATI
60
60
0.35
1
715.5 - AAC - SIN
1189
GARBERVILLE
LAYTONVILLE
60
60
39.99
1
715.5 - AAC - SIN
1190
GARCIA TAP
60
60
3.04
1
1/0 - ACSR - SING
1191
GLENN #1
60
60
33.37
1
715.5 - AAC - SIN
1192
(ej)
GLENN #2
60
60
34.69
1
715.5 - AAC - SIN
1193
GLENN #3
60
60
28.51
1
715.5 - AAC - SIN
1194
GLENN #4
60
60
12.54
1
715.5 - AAC - SIN
1195
GLENN #5
60
60
7.41
1
715.5 - AAC - SIN
1196
GOLD HILL #1
60
60
27.85
1
715.5 - AAC - SIN
1197
GONZALES #1 TAP
60
60
0.2
1
2/0 - CU - SINGLE
1198
GONZALES #2 TAP
60
60
0.3
1
2/0 - CU - SINGLE
1199
GRANITE ROCK TAP
60
60
2.39
1
4/0 - AAC - SINGL
1200
GREEN VALLEY
WATSONVILLE
60
60
4.74
1
397.5 - AAC - SIN
1201
GREENLEAF #2 TAP
60
60
0.62
1
715.5 - AAC - SIN
1202
GRONEMEYER TAP
60
60
0.83
1
1/0 - ACSR - SING
1203
GUSTINE #1 TAP
60
60
7.56
1
4/0 - AAC - SINGL
1204
GUSTINE #2 TAP
60
60
4.44
1
715.5 - AAC - SIN
1205
GWF #4 TAP
60
60
0.25
1
397.5 - AAC - SIN
1206
HALSEY
PLACER
60
60
4.94
1
397.5 - AAC - SIN
1207
HAMILTON BRANCH
CHESTER
60
60
12.27
1
4/0 - ACSR - SING
1208
HAMMER
COUNTRY CLUB
60
60
8.82
1
715.5 - AAC - SIN
1209
HARRINGTON TAP
60
60
0.53
1
1/0 - ACSR - SING
1210
HARTLEY
CLEARLAKE
60
60
6.66
1
4/0 - AAC - SINGL
1211
HAT CREEK #1
PIT #1
60
60
6.08
1
1/0 - ACSR - SING
1212
HAT CREEK #1
WESTWOOD
60
60
55.87
1
4/0 - CU - SINGLE
1213
HEADGATE TAP
60
60
0.97
1
4/0 - AAC - SINGL
1214
HEALDSBURG #1 TAP
60
60
0.25
1
4/0 - AAC - SINGL
1215
HEALDSBURG #2 TAP
60
60
0.16
1
471 - AAC - SINGL
1216
HERDLYN
BALFOUR
60
60
20.5
1
1/0 - CU - SINGLE
1217
HILLSDALE JCT
HALF MOON BAY
60
60
6.82
1
397.5 - AAC - SIN
1218
HUMBOLDT
EUREKA
60
60
4.7
1
715.5 - AAC - SIN
1219
HUMBOLDT
MAPLE CREEK
60
60
14.13
1
4/0 - ACSR - SING
1220
HUMBOLDT #1
60
60
11.05
1
715.5 - AAC - SIN
1221
HUMBOLDT BAY
EUREKA
60
60
5.61
1
715.5 - AAC - SIN
1222
HUMBOLDT BAY
HUMBOLDT #1
60
60
8.34
1
715.5 - AAC - SIN
1223
HUMBOLDT BAY
HUMBOLDT #2
60
60
6.45
1
1113 - AAC - SING
1224
HUMBOLDT BAY
RIO DELL JCT
60
60
18.4
1
1113 - AAC - SING
1225
IGNACIO
STAFFORD
60
6.13
1
715.5 - AAC - SIN
1226
IGNACIO
BOLINAS #1
60
60
15.06
1
715.5 - AAC - SIN
1227
IGNACIO
ALTO
60
60
17.79
1
715.5 - AAC - SIN
1228
IGNACIO
ALTO-SAUSALITO #1
60
60
17.83
1
4/0 - ACSR - SING
1229
IGNACIO
ALTO-SAUSALITO #2
60
60
17.83
1
4/0 - ACSR - SING
1230
IGNACIO
BOLINAS #2
60
60
28.22
1
715.5 - AAC - SIN
1231
INDUSTRIAL TAP
60
60
0.97
1
715.5 - AAC - SIN
1232
IONE TAP
60
60
4.09
1
4/0 - AAC - SINGL
1233
IUKA TAP
60
60
0.49
1
4 - CU - SINGLE
1234
JANES CREEK TAP
60
60
1.78
1
4/0 - AAC - SINGL
1235
JEFFERSON
HILLSDALE JCT
60
60
14.72
1
715.5 - AAC - SIN
1236
JEFFERSON
LAS PULGAS
60
60
6
1
715.5 - AAC - SIN
1237
JEFFERSON
STANFORD
60
60
7.64
1
715.5 - AAC - SIN
1238
JEFFERSON
STANFORD (UNDERGROUND)
60
60
1.52
1
1239
JEFFERSON
LAS PULGAS
60
60
0.18
1
1750 KCMIL - ALUM
1240
JEFFERSON #1
60
60
9.05
1
715.5 - AAC - SIN
1241
JENNINGS TAP
60
60
0.14
1
336.4 - AAC - SIN
1242
JOLON TAP
60
60
15.87
1
4/0 - AAC - SINGL
1243
KASSON
CARBONA
60
60
7.32
1
715.5 - AAC - SIN
1244
KASSON
BANTA #1
60
60
1.05
1
715.5 - AAC - SIN
1245
KASSON
LOUISE
60
60
8.79
1
715.5 - AAC - SIN
1246
KASSON #1
60
60
0.19
1
715.5 - AAC - SIN
1247
KESWICK
CASCADE
60
60
9.35
1
4/0 - AAC - SINGL
1248
KESWICK
TRINITY
60
60
30.42
1
336.4 - ACSR - SI
1249
KILARC
CEDAR CREEK
60
60
13.33
1
1/0 - ACSR - SING
1250
KILARC
DESCHUTES
60
60
27.28
1
2 - ACSR - SINGLE
1251
KILARC
VOLTA TIE
60
60
1.94
1
1/0 - ACSR - SING
1252
KING CITY
COBURN #1
60
60
21.91
1
715.5 - AAC - SIN
1253
KING CITY
COBURN #2
60
60
15.79
1
715.5 - AAC - SIN
1254
KONOCTI
MIDDLETOWN
60
60
19.87
1
715.5 - AAC - SIN
1255
KONOCTI
EAGLE ROCK
60
60
9.66
1
715.5 - AAC - SIN
1256
LAGUNA TAP
60
60
1.68
1
4/0 - AAC - SINGL
1257
LAGUNITAS TAP
60
60
0.6
1
1258
LAKEVILLE
PETALUMA C
60
60
5.36
1
250 - CU - SINGLE
1259
LAKEVILLE #1
60
60
11.16
1
397.5 - AAC - SIN
1260
LAKEVILLE #2
60
60
21.62
1
1/0 - CU - SINGLE
1261
LAS POSITAS
VASCO
60
60
1.5
1
715.5 - AAC - SIN
1262
LAURELES
OTTER
60
60
15.56
1
4/0 - ACSR - SING
1263
LAYTONVILLE
COVELO
60
60
16.09
1
715.5 - AAC - SIN
1264
LAYTONVILLE
WILLITS
60
60
23.14
1
715.5 - AAC - SIN
1265
(ek)
LEE TAP
60
60
5.85
1
4/0 - AAC - SINGL
1266
LIMESTONE TAP
60
60
1.73
1
2 - ACSR - SINGLE
1267
LIVERMORE
LAS POSITAS
60
60
3.63
1
715.5 - AAC - SIN
1268
LOCKEFORD
INDUSTRIAL
60
60
6.03
1
715.5 - AAC - SIN
1269
LOCKEFORD
LODI #2
60
60
9.41
1
715.5 - AAC - SIN
1270
LOCKEFORD
LODI #3
60
60
15.42
1
715.5 - AAC - SIN
1271
LOCKEFORD #1
60
60
12.85
1
715.5 - AAC - SIN
1272
LODI
INDUSTRIAL
60
60
0.97
1
715.5 - AAC - SIN
1273
LONE STAR TAP
60
60
1.18
1
1274
LOS COCHES TAP
60
60
1.33
1
4/0 - AAC - SINGL
1275
LOUISIANA PACIFIC (OROVILLE
60
60
0.16
1
1/0 - ACSR - SING
1276
LP FLAKEBOARD TAP
60
60
0.51
1
397.5 - AAC - SIN
1277
LYOTH TAP
60
60
1.34
1
4/0 - AAC - SINGL
1278
MANTECA
LOUISE
60
60
12.53
1
715.5 - AAC - SIN
1279
MANTECA #1
60
60
34.52
1
1/0 - CU - SINGLE
1280
MAPLE CREEK
HOOPA
60
60
29.13
1
1/0 - ACSR - SING
1281
MARSH TAP
60
60
3.97
1
1/0 - ACSR - SING
1282
MARTIN
SNEATH LANE
60
60
7.19
1
715.5 - AAC - SIN
1283
MCDONALD TAP
60
60
5.88
1
1/0 - ACSR - SING
1284
MENDOCINO
HARTLEY
60
60
23.17
1
4/0 - ACSR - SING
1285
MENDOCINO
PHILO JCT-HOPLAND
60
60
23.55
1
3/0 - CU - SINGLE
1286
MENDOCINO
WILLITS
60
60
14.52
1
2/0 - CU - SINGLE
1287
(el)
MENDOCINO
WILLITS-FORT BRAGG
60
60
43.77
1
715.5 - ALUM - SI
1288
MENDOCINO #1
60
60
7.48
1
3/0 - CU - SINGLE
1289
(em)
MENLO TAP
60
60
0.36
1
715.5 - AAC - BUN
1290
MIDDLE FORK #1
60
60
9.43
1
4/0 - ACSR - SING
1291
MIDDLE RIVER TAP
60
60
7.02
1
3 - CU - SINGLE 3
1292
MILLBRAE
SNEATH LANE
60
60
6.49
1
715.5 - AAC - SIN
1293
MONTA VISTA
BURNS
60
60
18.06
1
3/0 - CU - SINGLE
1294
MONTA VISTA
LOS ALTOS
60
60
7.13
1
715.5 - AAC - SIN
1295
MONTA VISTA
LOS GATOS
60
60
10.88
1
715.5 - AAC - SIN
1296
MONTA VISTA
PERMANENTE
60
60
1.19
1
397.5 - AAC - SIN
1297
MONTE RIO
FORT ROSS
60
60
14.3
1
715.5 - AAC - SIN
1298
MONTE RIO
FULTON
60
60
22.56
1
715.5 - AAC - SIN
1299
MTN GATE JCT
CASCADE
60
60
6.57
1
2/0 - CU - SINGLE
1300
MTN GATE TAP
60
60
0.7
1
1/0 - ACSR - SING
1301
MTN QUARRIES TAP
60
60
2.63
1
397.5 - AAC - SIN
1302
MULE CREEK TAP
60
60
0.01
1
4/0 - AAC - SINGL
1303
NARROWS #1 TAP
60
60
2.65
1
715.5 - AAC - SIN
1304
NARROWS #2 TAP
60
60
3.1
1
715.5 - AAC - SIN
1305
NAVY LAB TAP
60
60
0.19
1
2 - CU - SINGLE
1306
NEW HOGAN TAP
60
60
2.21
1
1/0 - ACSR - SING
1307
(en)
NEWARK
DECOTO
60
60
6.28
1
715.5 - AAC - SIN
1308
NEWARK
LIVERMORE
60
60
19.05
1
4/0 - CU - SINGLE
1309
NEWARK
VALLECITOS
60
60
12.39
1
715.5 - AAC - SIN
1310
NEWARK-SIERRA PAPERBOARD TA
60
60
0.29
1
715.5 - AAC - SIN
1311
NICOLAUS
CATLETT JCT
60
60
20.16
1
715.5 - AAC - SIN
1312
(eo)
NICOLAUS
CATLETT JCT
60
60
18.63
1
715.5 - AAC - SIN
1313
(ep)
NICOLAUS
CATLETT JCT (12KV)
60
60
18.63
1
715.5 - AAC - SIN
1314
NICOLAUS
MARYSVILLE
60
60
18.74
1
4/0 - CU - SINGLE
1315
NICOLAUS
PLAINFIELD
60
60
30.63
1
715.5 - AAC - SIN
1316
NICOLAUS
WILKINS SLOUGH
60
60
42.72
1
4 - CU - SINGLE 3
1317
OAK PARK TAP
60
60
0.87
1
4 - CU - SINGLE
1318
OILFIELDS
SARGENT CANYON
60
60
2.02
1
715.5 - AAC - SIN
1319
OILFIELDS
SALINAS RIVER
60
60
1.46
1
715.5 - AAC - SIN
1320
ORO FINO TAP
60
60
1.3
1
2 - ACSR - SINGLE
1321
OXBOW TAP
60
60
0.15
1
4/0 - ACSR - SING
1322
PACIFIC ETHANOL TAP
60
60
0.68
1
715.5 - AAC - SIN
1323
PACIFIC LUMBER (SCOTIA) TA
60
60
0.52
1
4/0 - AAC - SINGL
1324
PACIFIC OROVILLE POWER TAP
60
60
0.78
1
4/0 - AAC - SINGL
1325
PALERMO
OROVILLE #1
60
60
6.97
1
715.5 - AAC - SIN
1326
PALERMO
OROVILLE #2
60
60
10.13
1
715.5 - AAC - SIN
1327
PARDEE #1 TAP
60
60
4.33
1
2/0 - CU - SINGLE
1328
PARDEE #2 TAP
60
60
0.09
1
2/0 - CU - SINGLE
1329
(eq)
PARKS TAP
60
60
0.45
1
1/0 - ACSR - SING
1330
PEACHTON
PEASE
60
60
16.34
1
715.5 - AAC - SIN
1331
PEASE
HARTER
60
60
15.88
1
715.5 - AAC - SIN
1332
PEASE
MARYSVILLE-HARTER
60
60
10.29
1
715.5 - AAC - SIN
1333
PERMANENTE #1 TAP
60
60
0.31
1
397.5 - AAC - SIN
1334
PERMANENTE #2 TAP
60
60
0.51
1
397.5 - AAC - SIN
1335
PHILO JCT
ELK
60
60
37.25
1
397.5 - ACSR - SI
1336
PINE GROVE TAP
60
60
2.67
1
397.5 - ACSR - SI
1337
PIT #1
HAT CREEK #2-BURNEY
60
60
12.96
1
3/0 - CU - SINGLE
1338
PIT #1
MCARTHUR
60
60
7.3
1
1/0 - ACSR - SING
1339
(er)
PITTSBURG #1 TAP (NO FLY)
60
60
1.15
1
4/0 - CU - SINGLE
1340
PITTSBURG #2 TAP
60
60
1.19
1
3/0 - CU - SINGLE
1341
PLACER
DEL MAR
60
60
10.81
1
715.5 - AAC - SIN
1342
PLUMAS-SIERRA TAP
60
60
0.75
1
397.5 - ACSR - SI
1343
PORT COSTA BRICK TAP
60
60
1.9
1
3/0 - CU - SINGLE
1344
POTTER VALLEY
MENDOCINO
60
60
10.94
1
3/0 - CU - SINGLE
1345
POTTER VALLEY
WILLITS
60
60
13.16
1
1/0 - ACSR - SING
1346
RADUM
LIVERMORE
60
60
4.66
1
715.5 - AAC - SIN
1347
RADUM
VALLECITOS
60
60
10.62
1
715.5 - AAC - SIN
1348
RED BANK TAP
60
60
0.68
1
1/0 - ACSR - SING
1349
RIO DELL JCT
BRIDGEVILLE
60
60
21.25
1
1/0 - CU - SINGLE
1350
RIO DELL TAP
60
60
5.36
1
1/0 - CU - SINGLE
1351
ROBERTSON TAP
60
60
0.82
1
1/0 - ACSR - SING
1352
ROLLINS TAP
60
60
0.73
1
4/0 - ACSR - SING
1353
ROUGH & READY TAP
60
60
0.95
1
4/0 - AAC - SINGL
1354
SALADO
CROW CREEK SW STA
60
60
3.77
1
715.5 - ACSR - SI
1355
SALADO
NEWMAN #2
60
60
21.56
1
715.5 - AAC - SIN
1356
SALINAS
FORT ORD #1
60
60
10.22
1
715.5 - AAC - SIN
1357
SALINAS
FIRESTONE #1
60
60
6.18
1
715.5 - AAC - SIN
1358
SALINAS
FIRESTONE #2
60
60
17.21
1
715.5 - AAC - SIN
1359
SALINAS
LAGUNITAS
60
60
5.81
1
4/0 - CU - SINGLE
1360
SALINAS
LAURELES
60
60
27.46
1
266.8 - AAC - SIN
1361
SALINAS
FORT ORD #2
60
60
10.12
1
715.5 - AAC - SIN
1362
SALMON CREEK TAP
60
60
10.51
1
397.5 - AAC - SIN
1363
SAN ANDREAS (CCSF) TAP
60
60
0.39
1
397.5 - AAC - SIN
1364
SAN ARDO TAP
60
60
0.34
1
715.5 - AAC - SIN
1365
SAN BRUNO TAP
60
60
1.13
1
1/0 - ACSR - SING
1366
SAN MATEO
BAIR
60
60
13.99
1
397.5 - AAC - PAR
1367
SAN MATEO
HILLSDALE JCT
60
60
6.89
1
397.5 - AAC - SIN
1368
SAN RAMON
RADUM
60
60
7.06
1
715.5 - AAC - SIN
1369
SEBASTIANI TAP
60
60
0.01
1
4/0 - AAC - SINGL
1370
SENTER #1 TAP
60
60
0.23
1
336.4 - AAC - SIN
1371
(es)
SEQUOIA TAP
60
60
0.4
1
4/0 - AAC - SINGL
1372
SIERRA PAC IND (QUINCY) TAP
60
60
0.17
1
1373
SIERRA PINES LIMITED
60
60
0.4
1
4/0 - AAC - SINGL
1374
SIMPSON-KORBEL TAP
60
60
0.39
1
4/0 - AAC - SINGL
1375
SLAC TAP
60
60
1.41
1
397.5 - AAC - SIN
1376
SMARTVILLE
CAMP FAR WEST
60
60
17.81
1
715.5 - AAC - SIN
1377
(et)
SMARTVILLE
CAMP FAR WEST (12KV)
60
60
7.15
1
715.5 - AAC - SIN
1378
SMARTVILLE
MARYSVILLE
60
60
20.11
1
715.5 - AAC - SIN
1379
SMARTVILLE
NICOLAUS #1
60
60
29.6
1
715.5 - AAC - SIN
1380
SMARTVILLE
NICOLAUS #2
60
60
30.16
1
715.5 - AAC - SIN
1381
SMARTVILLE TAP
60
60
0.09
1
715.5 - AAC - SIN
1382
SNEATH LANE
HALF MOON BAY
60
60
15.41
1
715.5 - AAC - SIN
1383
SNEATH LANE
PACIFICA
60
60
3.26
1
715.5 - AAC - SIN
1384
SOLEDAD #1
60
60
15.5
1
397.5 - AAC - SIN
1385
SOLEDAD #2
60
60
18.86
1
4/0 - AAC - SINGL
1386
SOLEDAD #3
60
60
1.63
1
397.5 - AAC - SIN
1387
SOLEDAD #4
60
60
6.08
1
397.5 - AAC - SIN
1388
SPAULDING
SUMMIT
60
60
19.65
1
4/0 - CU - SINGLE
1389
SPAULDING #3
SPAULDING #1
60
60
1.09
1
1/0 - CU - SINGLE
1390
STAGG
COUNTRY CLUB #1
60
60
2.43
1
715.5 - AAC - SIN
1391
STAGG
COUNTRY CLUB #2
60
60
2.46
1
715.5 - AAC - SIN
1392
STAGG
HAMMER
60
60
4.25
1
715.5 - AAC - SIN
1393
(eu)
STANDARD #1 & #2 (12KV)
60
60
4.16
1
1 - UNKNOWN - UNK
1394
STANISLAUS RECOVERY TAP
60
60
0.11
1
397.5 - AAC - SIN
1395
STAUFFER TAP
60
60
0.58
1
1/0 - ACSR - SING
1396
(ev)
STOCKTON
NEWARK
60
60
14.59
1
3/0 - CU - SINGLE
1397
STOCKTON A
WEBER #1
60
60
13.2
1
715.5 - AAC - SIN
1398
STOCKTON A
WEBER #2
60
60
9.87
1
715.5 - AAC - SIN
1399
STOCKTON A
WEBER #3
60
60
9.81
1
715.5 - AAC - SIN
1400
STOCKTON A #1
60
60
5.58
1
715.5 - AAC - SIN
1401
SUMIDEN WIRE PRODUCTS TAP
60
60
0.19
1
397.5 - AAC - SIN
1402
SUNOL TAP
60
60
0.08
1
4/0 - AAC - SINGL
1403
SUTTER HOME
SUTTER HOME SW STA
60
60
0.03
1
715.5 - AAC - SIN
1404
SUTTER HOME SW STA
LOCKEFORD-LODI
60
60
29.74
1
715.5 - AAC - SIN
1405
SUTTER HOME SW STA
STAGG
60
60
17.13
1
715.5 - AAC - SIN
1406
TABLE MTN
PEACHTON
60
60
14.84
1
715.5 - AAC - SIN
1407
TERMINOUS TAP
60
60
3.01
1
2/0 - ACSR - SING
1408
TEXACO TAP
60
60
0.72
1
397.5 - AAC - SIN
1409
TOCALOMA TAP
60
60
1.03
1
2 - ACSR - SINGLE
1410
TRAVIS TAP
60
60
2.88
1
715.5 - AAC - SIN
1411
TRINIDAD TAP
60
60
1.34
1
1 - CU - SINGLE
1412
TRINITY
MAPLE CREEK
60
60
55.45
1
4/0 - ACSR - SING
1413
TULUCAY
NAPA #1
60
60
9.72
1
715.5 - AAC - SIN
1414
TULUCAY
NAPA #2
60
60
3.93
1
715.5 - AAC - SIN
1415
ULTRA POWER TAP
60
60
1.17
1
4/0 - AAC - SINGL
1416
UNION CHEMICAL TAP
60
60
1.04
1
715.5 - AAC - SIN
1417
URICH TAP
60
60
0.21
1
4/0 - AAC - SINGL
1418
US WINDPOWER TAP
60
60
1.52
1
4/0 - AAC - SINGL
1419
VACA
PLAINFIELD
60
60
29.83
1
715.5 - AAC - SIN
1420
VALLEY SPRINGS
CALAVERAS CEMENT
60
60
7.91
1
715.5 - AAC - SIN
1421
VALLEY SPRINGS
MARTELL #1
60
60
12.75
1
1113 - AAC - SING
1422
VALLEY SPRINGS
CLAY
60
60
17.3
1
715.5 - AAC - SIN
1423
(ew)
VALLEY SPRINGS #1
60
60
27.27
1
1113 - AAC - SING
1424
VALLEY SPRINGS #2
60
60
25.65
1
1113 - AAC - SING
1425
VASCO
HERDLYN
60
60
10.97
1
715.5 - AAC - SIN
1426
VICTOR TAP
60
60
0.06
1
4/0 - AAC - SINGL
1427
VIEJO
MONTEREY
60
60
2.28
1
715.5 - AAC - SIN
1428
VOLTA
DESCHUTES
60
60
20.86
1
2/0 - CU - SINGLE
1429
VOLTA
SOUTH
60
60
4.86
1
1 - CU - SINGLE 2
1430
WADHAM TAP
60
60
1.68
1
4/0 - AAC - SINGL
1431
WASHOE TAP
60
60
1.04
1
4/0 - AAC - SINGL
1432
WATERSHED TAP
60
60
0.28
1
4/0 - AAC - SINGL
1433
WATSONVILLE
SALINAS
60
60
28.39
1
3/0 - CU - SINGLE
1434
WEBER
FRENCH CAMP #1
60
60
6.07
1
715.5 - AAC - SIN
1435
WEBER
FRENCH CAMP #2
60
60
10.89
1
715.5 - AAC - SIN
1436
WEBER
MORMON JCT
60
60
17.67
1
715.5 - AAC - SIN
1437
WEIMAR
HALSEY
60
60
6.28
1
397.5 - AAC - SIN
1438
WEIMAR #1
60
60
13.98
1
80 - ACSR - SINGL
1439
WEST POINT
VALLEY SPRINGS
60
60
21.66
1
715.5 - AAC - SIN
1440
WEST SAC COM TOWERS
60
0.02
1
1441
WESTINGHOUSE TAP
60
60
7.97
1
4/0 - CU - SINGLE
1442
WILLOW PASS
CONTRA COSTA
60
60
10.82
1
715.5 - AAC - SIN
1443
WIND FARMS
60
60
3.75
1
715.5 - AAC - SIN
1444
WINDSOR
FITCH MOUNTAIN
60
60
21.24
1
4/0 - ACSR - SING
1445
WINTU TAP
60
60
1.86
1
1/0 - ACSR - SING
1446
WOHLER TAP
60
60
1.44
1
2 - ACSR - SINGLE
1447
WOODBRIDGE TAP
60
60
0.53
1
4/0 - AAC - SINGL
1448
YUBA CITY COGEN TAP
60
60
0.8
1
477 - ACSS - SING
1449
ZOND WIND TAP
60
60
1.19
1
1450
A
Y #1 (UNDERGROUND IDLE)
0.35
1
1250 KCMIL - CU
1451
Summary of Lines
1452
listed individually above
1453
Towers & Poles
500
1,328
29,217,173
461,063,372
490,280,545
1,594,870
9,529,274
11,124,144
1454
230
5,335
77,883,619
1,757,640,266
1,835,523,885
6,408,707
38,291,725
44,700,432
1455
115
6,114
92,589,376
1,052,639,078
1,145,228,454
7,344,486
43,882,962
51,227,448
1456
70
1,544
14,828,234
225,301,498
240,129,732
1,854,741
11,081,991
12,936,732
1457
60
3,905
34,646,232
528,067,383
562,713,615
4,690,909
28,027,963
32,718,872
1458
Other Undground
1459
Transmission Lines
230
86
2,790,742
238,509,403
241,300,145
139,269
839,038
978,307
1460
115
84
122,163
516,524,425
516,646,588
136,226
820,704
956,930
1461
70
1462
60
5
21,150,299
21,150,299
8,733
52,614
61,347
1463
Transmission Roads
103,255,426
103,255,426
36
36,802.57
1,450
252,077,539
4,904,151,150
5,156,228,689
22,177,941
132,526,271
154,704,212


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

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(b) Concept: TransmissionLineStartPoint

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(c) Concept: TransmissionLineStartPoint

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(d) Concept: TransmissionLineStartPoint

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(e) Concept: TransmissionLineStartPoint

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(f) Concept: TransmissionLineStartPoint

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(g) Concept: TransmissionLineStartPoint

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(h) Concept: TransmissionLineStartPoint

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(i) Concept: TransmissionLineStartPoint

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(j) Concept: TransmissionLineStartPoint

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(k) Concept: TransmissionLineStartPoint

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(l) Concept: TransmissionLineStartPoint

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(m) Concept: TransmissionLineStartPoint

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(n) Concept: TransmissionLineStartPoint

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(o) Concept: TransmissionLineStartPoint

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(p) Concept: TransmissionLineStartPoint

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(q) Concept: TransmissionLineStartPoint

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(r) Concept: TransmissionLineStartPoint

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(s) Concept: TransmissionLineStartPoint

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(t) Concept: TransmissionLineStartPoint

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(u) Concept: TransmissionLineStartPoint

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(v) Concept: TransmissionLineStartPoint

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(w) Concept: TransmissionLineStartPoint

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(x) Concept: TransmissionLineStartPoint

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(y) Concept: TransmissionLineStartPoint

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(z) Concept: TransmissionLineStartPoint

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(aa) Concept: TransmissionLineStartPoint

IDLE

(ab) Concept: TransmissionLineStartPoint

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(ac) Concept: TransmissionLineStartPoint

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(ad) Concept: TransmissionLineStartPoint

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(ae) Concept: TransmissionLineStartPoint

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(af) Concept: TransmissionLineStartPoint

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(ag) Concept: TransmissionLineStartPoint

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(ah) Concept: TransmissionLineStartPoint

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(ai) Concept: TransmissionLineStartPoint

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(aj) Concept: TransmissionLineStartPoint

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(ak) Concept: TransmissionLineStartPoint

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(al) Concept: TransmissionLineStartPoint

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(am) Concept: TransmissionLineStartPoint

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(an) Concept: TransmissionLineStartPoint

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(ao) Concept: TransmissionLineStartPoint

IDLE

(ap) Concept: TransmissionLineStartPoint

BUNDLE

(aq) Concept: TransmissionLineStartPoint

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(ar) Concept: TransmissionLineStartPoint

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(as) Concept: TransmissionLineStartPoint

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(at) Concept: TransmissionLineStartPoint

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(au) Concept: TransmissionLineStartPoint

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(av) Concept: TransmissionLineStartPoint

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(aw) Concept: TransmissionLineStartPoint

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(ax) Concept: TransmissionLineStartPoint

BUNDLE

(ay) Concept: TransmissionLineStartPoint

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(az) Concept: TransmissionLineStartPoint

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(ba) Concept: TransmissionLineStartPoint

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(bb) Concept: TransmissionLineStartPoint

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(bc) Concept: TransmissionLineStartPoint

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(bd) Concept: TransmissionLineStartPoint

 

(be) Concept: TransmissionLineStartPoint

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(bf) Concept: TransmissionLineStartPoint

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(bg) Concept: TransmissionLineStartPoint

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(bh) Concept: TransmissionLineStartPoint

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(bi) Concept: TransmissionLineStartPoint

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(bj) Concept: TransmissionLineStartPoint

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(bk) Concept: TransmissionLineStartPoint

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(bl) Concept: TransmissionLineStartPoint

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(bm) Concept: TransmissionLineStartPoint

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(bn) Concept: TransmissionLineStartPoint

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(bo) Concept: TransmissionLineStartPoint

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(bp) Concept: TransmissionLineStartPoint

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(bq) Concept: TransmissionLineStartPoint

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(br) Concept: TransmissionLineStartPoint

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(bs) Concept: TransmissionLineStartPoint

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(bt) Concept: TransmissionLineStartPoint

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(bu) Concept: TransmissionLineStartPoint

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(bv) Concept: TransmissionLineStartPoint

BUNDLE

(bw) Concept: TransmissionLineStartPoint

 

(bx) Concept: TransmissionLineStartPoint

BUNDLE

(by) Concept: TransmissionLineStartPoint

BUNDLE

(bz) Concept: TransmissionLineStartPoint

IDLE

(ca) Concept: TransmissionLineStartPoint

IDLE

(cb) Concept: TransmissionLineStartPoint

IDLE

(cc) Concept: TransmissionLineStartPoint

IDLE

(cd) Concept: TransmissionLineStartPoint

BUNDLE

(ce) Concept: TransmissionLineStartPoint

BUNDLE, IDLE

(cf) Concept: TransmissionLineStartPoint

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(cg) Concept: TransmissionLineStartPoint

BUNDLE, IDLE

(ch) Concept: TransmissionLineStartPoint

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(ci) Concept: TransmissionLineStartPoint

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(cj) Concept: TransmissionLineStartPoint

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(ck) Concept: TransmissionLineStartPoint

BUNDLE

(cl) Concept: TransmissionLineStartPoint

IDLE

 

(cm) Concept: TransmissionLineStartPoint

IDLE

(cn) Concept: TransmissionLineStartPoint

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(co) Concept: TransmissionLineStartPoint

IDLE

(cp) Concept: TransmissionLineStartPoint

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(cq) Concept: TransmissionLineStartPoint

BUNDLE

(cr) Concept: TransmissionLineStartPoint

IDLE

(cs) Concept: TransmissionLineStartPoint

IDLE

(ct) Concept: TransmissionLineStartPoint

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(cu) Concept: TransmissionLineStartPoint

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(cv) Concept: TransmissionLineStartPoint

IDLE

 

(cw) Concept: TransmissionLineStartPoint

IDLE

(cx) Concept: TransmissionLineStartPoint

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(cy) Concept: TransmissionLineStartPoint

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(cz) Concept: TransmissionLineStartPoint

IDLE

(da) Concept: TransmissionLineStartPoint

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(db) Concept: TransmissionLineStartPoint

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(dc) Concept: TransmissionLineStartPoint

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(dd) Concept: TransmissionLineStartPoint

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(de) Concept: TransmissionLineStartPoint

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(df) Concept: TransmissionLineStartPoint

BUNDLE

(dg) Concept: TransmissionLineStartPoint

IDLE

(dh) Concept: TransmissionLineStartPoint

IDLE

(di) Concept: TransmissionLineStartPoint

IDLE

(dj) Concept: TransmissionLineStartPoint

IDLE

(dk) Concept: TransmissionLineStartPoint

IDLE

(dl) Concept: TransmissionLineStartPoint

BUNDLE

(dm) Concept: TransmissionLineStartPoint

IDLE

(dn) Concept: TransmissionLineStartPoint

IDLE

(do) Concept: TransmissionLineStartPoint

BUNDLE

(dp) Concept: TransmissionLineStartPoint

ALUM

(dq) Concept: TransmissionLineStartPoint

IDLE

(dr) Concept: TransmissionLineStartPoint

ALUM

(ds) Concept: TransmissionLineStartPoint

IDLE

(dt) Concept: TransmissionLineStartPoint

IDLE

(du) Concept: TransmissionLineStartPoint

IDLE

(dv) Concept: TransmissionLineStartPoint

IDLE

(dw) Concept: TransmissionLineStartPoint

ALUM

(dx) Concept: TransmissionLineStartPoint

ALUM

(dy) Concept: TransmissionLineStartPoint

IDLE

(dz) Concept: TransmissionLineStartPoint

ALUM

(ea) Concept: TransmissionLineStartPoint

IDLE

(eb) Concept: TransmissionLineStartPoint

IDLE

(ec) Concept: TransmissionLineStartPoint

BUNDLE

(ed) Concept: TransmissionLineStartPoint

BUNDLE

(ee) Concept: TransmissionLineStartPoint

IDLE

(ef) Concept: TransmissionLineStartPoint

IDLE

(eg) Concept: TransmissionLineStartPoint

BUNDLE

(eh) Concept: TransmissionLineStartPoint

BUNDLE

(ei) Concept: TransmissionLineStartPoint

IDLE

(ej) Concept: TransmissionLineStartPoint

BUNDLE

(ek) Concept: TransmissionLineStartPoint

IDLE

(el) Concept: TransmissionLineStartPoint

ALUM

(em) Concept: TransmissionLineStartPoint

BUNDLE

(en) Concept: TransmissionLineStartPoint

IDLE

(eo) Concept: TransmissionLineStartPoint

IDLE

(ep) Concept: TransmissionLineStartPoint

IDLE

(eq) Concept: TransmissionLineStartPoint

IDLE

(er) Concept: TransmissionLineStartPoint

IDLE

(es) Concept: TransmissionLineStartPoint

IDLE

(et) Concept: TransmissionLineStartPoint

IDLE

(eu) Concept: TransmissionLineStartPoint

IDLE

(ev) Concept: TransmissionLineStartPoint

IDLE

(ew) Concept: TransmissionLineStartPoint

BUNDLE

(ex) Concept: SupportingStructureOfTransmissionLineType

SSP - Single Steel Poles; SWP - Single Wood Poles; WH - Wood "H" Structures; T - Steel Towers; UG - Underground


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSMISSION LINES ADDED DURING YEAR
  1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines.
  2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
  3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.
LINE DESIGNATION SUPPORTING STRUCTURE CIRCUITS PER STRUCTURE CONDUCTORS LINE COST
Line No.
TransmissionLineStartPoint
From
TransmissionLineEndPoint
To
LengthOfTransmissionLineAdded
Line Length in Miles
SupportingStructureOfTransmissionLineType
Type
AverageNumberOfSupportingStructuresOfTransmissionLinePerMiles
Average Number per Miles
NumberOfTransmissionCircuitsPerStructurePresent
Present
NumberOfTransmissionCircuitsPerStructureUltimate
Ultimate
ConductorSize
Size
ConductorSpecification
Specification
ConductorConfigurationAndSpacing
Configuration and Spacing
OperatingVoltageOfTransmissionLine
Voltage KV (Operating)
CostOfLandAndLandRightsTransmissionLinesAdded
Land and Land Rights
CostOfPolesTowersAndFixturesTransmissionLinesAdded
Poles, Towers and Fixtures
CostOfConductorsAndDevicesTransmissionLinesAdded
Conductors and Devices
AssetRetirementCostsTransmissionLines
Asset Retire. Costs
CostOfTransmissionLinesAdded
Total
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)
1
RECONDUCTORING WORK
2
OVERHEAD CONSTRUCTION
3
Semitropic-Midway
4
Semitropic Sub
Midway Substation
14.2
17
1
1
T1 8.5 FT
115
4,773,941
1,267,713
6,041,654
5
Job Order #74001000
6
Headgate Tap
7
Headgate Metering station
Glenn #3
0.9
21
1
1
T1 8.5 FT
60
537,454
344,306
881,760
8
Job Order #74000976
9
R2 HELM-KERMAN 70KV RE-CONDUCT
10
T-LINE TP 11/4
TP 9/6
2
16
1
1
Various
70
528,710
1,431,542
1,960,252
11
Job Order #74001043
12
Cortina #3
13
Cortina Sub
Wadham Junction
5.5
17
1
1
Various
60
989,918
3,400,476
4,390,394
14
Job Order #74001094
15
Missouri Flat
16
Gold Hill
Shingle Springs sub
12.2
15
2
2
Various
115
4,162,563
25,240,911
20,740,114
50,143,588
17
Job Order #74001423
18
ENG~LODI STIG-EIGHT MILE RECON
19
(T-LINE) Lodi Sting
Eight Mile Road
2.3
6
2
2
(h)
16.5' twr
230
165,363
143,117
1,906,788
2,215,268
20
Job Order #74003601
21
Smartville_ E Nicolaus Inside
22
BAFB Smartville-Nicolaus 5/112
9/183
4.1
18
1
1
Various
60
1,034,547
978,995
2,013,542
23
Job Order #74003265
24
Vaca-Vacaville-Cordelia 115kV
25
Vacaville
Cordelia
25.3
5
2
2
A 10 FT
115
505,717
221,294
727,011
26
Job Order #74004611
27
Vaca-Vacaville-Jameson-North
28
Tower 115 kV NERC Project
29
Vaca-Vacaville-Jameson North
30
Tower
Vaca-Vacaville Cordelia 115
11.7
8
2
2
Vert10 FT
115
8,657,789
14,925,557
23,583,346
31
Job Order #74004612/74012740
32
Sobrante R
33
Sobrante R #1
Sobrante R #2
0.5
7
2
2
Vert10 FT
115
1,374,811
4,075,738
5,450,549
34
Job Order #74004614
35
Fulton Junction-Vaca 115kV
36
NERC Project
37
Fulton Jct
Vacaville
11.8
7
2
2
Vert10 FT
115
4,246,118
4,575,030
8,821,148
38
Job Order #74004616
39
Madison-Vaca 115kV NERC
40
Project
41
Madison
Vacaville
11.8
7
2
2
Vert10 FT
115
22,652
1,433,086
1,455,738
42
Job Order #74006767
43
GP Gypsum San Leandro-Oakland
44
J Tap Remo
45
San Leandro-Oakland JTap 115kV
Domtar #2 Sub.
0.1
1
2
2
Vert10 FT
115
85,178
85,178
46
Job Order #74016660
47
El Dorado-Missouri Flat#1115kV
48
002/020
03/023
0.5
3
2
2
SS2, DDE
115
724,914
348,679
1,073,593
49
Job Order #74010782
50
REMOVALS
51
OVERHEAD CONSTRUCTION
52
Big Bend-Clayton Idle Removal
53
074/551
86/643
5.98
8
2
2
Removal
115
862,365
3,723,048
4,585,413
54
Job Order #74000663
55
Brighton-Grand Island Idle
56
Removal
57
24/189
41/307
16.42
7
2
2
Removal
115
2,622,246
3,222,013
5,844,259
58
Job Order #74010461
44
TOTAL
125.3
163
27
27
4,327,926
52,265,210
62,679,557
119,272,693


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SupportingStructureOfTransmissionLineType

LSDP, TSP, SWP, TOWER

(b) Concept: SupportingStructureOfTransmissionLineType

Lattice Towers, TSP

(c) Concept: ConductorSize

266.8, 1113, 397.5

(d) Concept: ConductorSize

715, 1/0, 397

(e) Concept: ConductorSize

715.5, 3/0, 397.5, 2/0

(f) Concept: ConductorSpecification

AAC, ACSR, AAC

(g) Concept: ConductorSpecification

AAC, CU, ACSR, CU

(h) Concept: ConductorConfigurationAndSpacing

16.5' twr arm spacing


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
SUBSTATIONS
  1. Report below the information called for concerning substations of the respondent as of the end of the year.
  2. Substations which serve only one industrial or street railway customer should not be listed below.
  3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown.
  4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).
  5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity.
  6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
VOLTAGE (In MVa)
Line No.
SubstationNameAndLocation
Name and Location of Substation
(a)
SubstationCharacterDescription
Character of Substation
(b)
PrimaryVoltageLevel
Primary Voltage (In MVa)
(c)
SecondaryVoltageLevel
Secondary Voltage (In MVa)
(d)
TertiaryVoltageLevel
Tertiary Voltage (In MVa)
(e)
SubstationInServiceCapacity
Capacity of Substation (In Service) (In MVa)
(f)
NumberOfTransformersInService
Number of Transformers In Service
(g)
Number of Spare Transformers
(h)
ConversionApparatusAndSpecialEquipmentType
Conversion Apparatus and Special Equipment, Type of Equipment
(i)
NumberOfConversionApparatusAndSpecialEquipmentUnits
Conversion Apparatus and Special Equipment, Number of Units
(j)
CapacityOfConversionApparatusAndSpecialEquipment
Conversion Apparatus and Special Equipment, Total Capacity (In MVa)
(k)
1
ARCO SUB, Lost Hills
Transmission
230
70
13.2
360
6
1
2.00000
2
ATLANTIC SUB, Roseville
Transmission
230
60
13.2
334
4
1
2.00000
3
ATLANTIC SUB, Roseville
Transmission
230
115
13.2
840
2
2.00000
4
BAIR SUB, Redwood City
Transmission
115
60
13.2
80
3
1.00000
5
BELLOTA SUB, Bellota
Transmission
230
115
13.2
400
2
Sync Cond
1
40
6
BORDEN SUB, Madera
Transmission
230
70
13.2
400
2
2.00000
7
BRIDGEVILLE SUB, Bridgeville
Transmission
115
60
13.2
90
3
1
1.00000
8
BRIGHTON SUB, Sacramento
Transmission
230
115
13.2
840
2
2.00000
9
BUTTE SUB, Chico
Transmission
115
60
13.2
90
3
1
1.00000
10
CASCADE SUB, Pine Grove
Transmission
115
60
13.2
76
3
1.00000
11
CHRISTIE SUB, Hercules
Transmission
115
60
13.2
190
4
1
2.00000
12
COBURN SUB, King City
Transmission
230
60
13.2
214
6
1
2.00000
13
CONTRA COSTA SUBSTATION, Antioch
Transmission
115
60
13.2
120
6
2
2.00000
14
CONTRA COSTA SUBSTATION, Antioch
Transmission
230
115
13.2
180
3
1
1.00000
15
COOLEY LANDING SUB, Palo Alto
Transmission
115
60
13.8
290
4
1
2.00000
16
CORCORAN SUB, Corcoran
Transmission
115
70
13.2
90
3
1
1.00000
17
CORTINA SUB, Williams
Transmission
115
60
13.2
200
1
1.00000
18
CORTINA SUB, Williams
Transmission
230
115
13.2
588
4
2
2.00000
19
COTTONWOOD SUB, Cottonwood
Transmission
230
60
13.2
400
2
2.00000
20
COTTONWOOD SUB, Cottonwood
Transmission
230
115
13.2
240
6
1
2.00000
21
DEL MONTE SUB, Monterey
Transmission
115
60
13.2
400
2
2.00000
22
DIVIDE SUB, Orcutt
Transmission
115
70
13.2
170
6
1
2.00000
23
EAGLE ROCK SUB, Geysers
Transmission
115
60
68
3
1
1.00000
24
EAST NICOLAUS SUB, E. Nicolaus
Transmission
115
60
400
2
2.00000
25
EASTSHORE SUB, Hayward
Transmission
230
115
840
2
2.00000
26
EVERGREEN SUB, San Jose
Transmission
115
60
13.2
80
3
1
1.00000
27
FULTON SUB, Fulton
Transmission
115
60
13.2
600
2
2.00000
28
FULTON SUB, Fulton
Transmission
230
115
13.2
823
4
1
2.00000
29
GATES SUB, Huron
Transmission
115
70
13.2
117
3
1
1.00000
30
GATES SUB, Huron
Transmission
230
115
13.2
120
3
1.00000
31
GATES SUB, Huron
Transmission
500
230
13.2
1122
3
1
2.00000
32
GLENN SUB, Orland
Transmission
230
60
13.2
255
4
1
2.00000
33
GOLD HILL SUB, Folsom
Transmission
115
60
13.2
80
3
1.00000
34
GOLD HILL SUB, Folsom
Transmission
230
115
13.2
840
2
2.00000
35
GREEN VALLEY SUB, Watsonville
Transmission
115
60
38
3
1.00000
36
HELM SUB, San Joaquin
Transmission
230
70
13.2
134
3
1.00000
37
HENRIETTA SUB, Lamoore
Transmission
230
70
13.2
400
2
2.00000
38
HENRIETTA SUB, Lamoore
Transmission
230
115
2.4
180
3
1
1.00000
39
HERDLYN SUB, Tracy
Transmission
70
60
2.4
50
3
1
1.00000
40
HERNDON SUB, Herndon
Transmission
230
115
13.2
1260
3
Sync Cond
2
80
41
HOPLAND SUB, Hopland
Transmission
115
60
13.2
40
1
1.00000
42
HUMBOLDT SUB SUB, Eureka
Transmission
115
60
13.2
400
2
SVC
1
50
43
IGNACIO SUB, Ignacio
Transmission
115
60
13.2
400
2
2.00000
44
IGNACIO SUB, Ignacio
Transmission
230
115
13.2
823
4
1
2.00000
45
JEFFERSON SUB, Redwood City
Transmission
230
60
13.2
400
2
2.00000
46
KASSON SUB, Tracy
Transmission
115
60
13.2
76
3
1.00000
47
KERN PP SUB, Bakersfield
Transmission
115
70
13.2
400
2
2.00000
48
KERN PP SUB, Bakersfield
Transmission
230
115
13.2
1260
3
3.00000
49
KINGSBURG SUB, Kingsburg
Transmission
115
70
13.8
90
3
1
1.00000
50
LAKEVILLE SUB, Petaluma
Transmission
230
60
13.2
400
2
2.00000
51
LAKEVILLE SUB, Petaluma
Transmission
230
115
13.2
840
2
2.00000
52
LAS POSITAS SUB, Livermore
Transmission
230
60
13.2
90
3
1.00000
53
LOCKEFORD SUB, Lockeford
Transmission
230
60
13.2
400
2
2.00000
54
LOS BANOS SUB, Los Banos
Transmission
230
70
13.2
334
4
2.00000
55
LOS BANOS SUB, Los Banos
Transmission
500
230
13.8
840
3
1
1.00000
56
LOS ESTEROS SUB,
Transmission
230
115
12
840
2
2.00000
57
MANTECA SUB, Manteca
Transmission
115
60
13.2
100
1
1
2.00000
58
MCCALL SUB, Selma
Transmission
230
115
13.2
1243
5
1
Sync Cond
2
80
59
MENDOCINO SUB, Redwood Valley
Transmission
115
60
13.2
280
4
1
2.00000
60
MENDOTA SUB, Mendota
Transmission
115
70
12
90
3
1
1.00000
61
MERCED SUB, Merced
Transmission
115
70
6.6
50
3
1.00000
62
MESA SUB, Nipomo
Transmission
230
115
13.2
840
2
2.00000
63
METCALF SUB, San Jose
Transmission
500
230
13.8
3366
9
2
3.00000
64
METCALF SUB, San Jose
Transmission
230
115
13.2
1630
10
1
4.00000
65
MIDWAY SUB, Buttonwillow
Transmission
230
115
13.2
1260
3
3.00000
66
MIDWAY SUB, Buttonwillow
Transmission
500
230
13.8
3364
9
2
3.00000
67
MILLBRAE SUB, Millbrae
Transmission
115
60
13.8
90
3
1.00000
68
MONTA VISTA SUB, Cupertino
Transmission
115
60
13.2
200
1
1.00000
69
MONTA VISTA SUB, Cupertino
Transmission
230
60
134
3
1
1.00000
70
MONTA VISTA SUB, Cupertino
Transmission
230
115
13.2
1260
3
1.00000
71
MORAGA SUB, Orinda
Transmission
230
115
13.2
1243
5
1
3.00000
72
MORRO BAY PP SWYD, Morro Bay
Transmission
230
115
13.2
269
3
1
1.00000
73
MOSS LANDING PP SUB, Moss Landing
Transmission
230
115
13.2
1680
4
2.00000
74
MOSS LANDING PP SUB, Moss Landing
Transmission
500
230
13.8
1122
3
1
1.00000
75
NEW KEARNEY SUB, FRESNO
Transmission
230
70
13.2
200
4
1
1.00000
76
NEWARK SUB, Fremont
Transmission
115
60
13.2
80
3
1.00000
77
NEWARK SUB, Fremont
Transmission
230
115
13.2
1646
8
1
SVC
1
220
78
ORO LOMA SUB, Dos Palos
Transmission
115
70
13.2
60
3
1.00000
79
PALERMO SUB, Palermo
Transmission
230
60
168
3
1
1.00000
80
PALERMO SUB, Palermo
Transmission
230
115
13.2
420
1
1.00000
81
PANOCHE SUB, Mendota
Transmission
230
115
13.2
840
2
2.00000
82
PEASE SUB, Tierra Buena
Transmission
115
60
13.2
80
3
1
1.00000
83
PITTSBURG PP SUB,
Transmission
230
115
13.2
840
2
2.00000
84
PLACER SUB, Auburn
Transmission
115
60
95
3
1.00000
85
RAVENSWOOD SUB, Menlo Park
Transmission
230
115
13.2
823
4
1
2.00000
86
REEDLEY SUB, Reedley
Transmission
115
70
13.2
190
4
1
2.00000
87
RIO OSO SUB, Rio Oso
Transmission
230
115
13.2
254
6
2.00000
88
ROUND MOUNTAIN SUB, Rd Mtn
Transmission
500
230
13.8
1122
3
1
1.00000
89
SALADO SUB, Patterson
Transmission
115
60
13.2
200
2
2.00000
90
SALINAS SUB, Salinas
Transmission
115
60
13.2
400
2
2.00000
91
SAN FRAN A (POTRERO PP) SUB, San Francisco
Transmission
230
115
13.2
420
1
1.00000
92
SAN FRAN H (MARTIN) SUB, Daly City
Transmission
115
60
100
1
1.00000
93
SAN FRAN H (MARTIN) SUB, Daly City
Transmission
230
115
823
4
1
2.00000
94
SAN LUIS OBISPO SUB, SLO
Transmission
115
70
13.2
200
1
1.00000
95
SAN MATEO SUB, San Mateo
Transmission
115
60
200
2
2.00000
96
SAN MATEO SUB, San Mateo
Transmission
230
115
1260
3
Sync Cond
2
88
97
SAN RAMON SUB, San Ramon
Transmission
230
60
13.2
90
3
1
1.00000
98
SANGER SUB, Fresno
Transmission
115
70
6.6
30
3
1
1.00000
99
SCHINDLER SUB, Five Points
Transmission
115
70
13.2
90
3
1
1.00000
100
SEMITROPIC SUB, Wasco
Transmission
115
70
13.8
90
3
1
1.00000
101
SOBRANTE SUB, Orinda
Transmission
230
115
823
4
1
2.00000
102
SOLEDAD SUB, Soledad
Transmission
115
60
75
6
2.00000
103
STAGG SUB, Stockton
Transmission
230
60
13.2
600
2
2.00000
104
TABLE MOUNTAIN SUB, Oroville
Transmission
230
115
1008
5
1
3.00000
105
TABLE MOUNTAIN SUB, Oroville
Transmission
500
230
13.8
1122
3
1
1.00000
106
TAFT SUB, Taft
Transmission
115
70
13.2
162
4
2.00000
107
TEMPLETON SUB, TEMPLETON
Transmission
230
70
13.2
175
1
1.00000
108
TESLA SUB, Tracy
Transmission
230
115
13.2
806
6
1
2.00000
109
TESLA SUB, Tracy
Transmission
500
230
13.2
3366
9
2
3.00000
110
TRINITY SUB, Weaverville
Transmission
115
60
13.2
90
3
1
1.00000
111
TULUCAY SUB, Napa
Transmission
230
60
13.2
400
2
2.00000
112
VACA DIXON SUB, Vacaville
Transmission
115
60
13.2
290
4
1
2.00000
113
VACA DIXON SUB, Vacaville
Transmission
230
115
13.2
1094
8
3.00000
114
VACA DIXON SUB, Vacaville
Transmission
500
230
13.8
2244
6
1
2.00000
115
VALLEY SPRINGS SUB, Valley Springs
Transmission
230
60
13.2
334
4
1
2.00000
116
WEBER SUB, Stockton
Transmission
230
60
13.2
600
2
2.00000
117
WHEELER RIDGE SUB, Bakersfield
Transmission
115
70
13.2
60
3
1
1.00000
118
WHEELER RIDGE SUB, Bakersfield
Transmission
230
70
13.2
400
2
2.00000
119
WILSON SUB, Merced
Transmission
230
115
13.2
689
4
1
2.00000
120
7th STANDARD SUB, Bakersfield
Distribution
115
21
45
1
1.00000
121
AIRWAYS SUB, Fresno, Ca.
Distribution
115
12
7.2
90
2
2.00000
122
ALHAMBRA SUB, Martinez
Distribution
115
12
7.2
27
2
2.00000
123
ALLEGHANY SUB, Alleghany
Distribution
60
12
7.2
13
1
1.00000
124
ALMADEN SUB, San Jose
Distribution
60
12
7.2
60
2
2.00000
125
ALPAUGH SUB, Tulare
Distribution
115
12
41
2
2.00000
126
ALTO SUB, Mill Valley
Distribution
60
12
2.4
49
4
1
2.00000
127
AMES DISTRIBUTION SUB, Mountain View
Distribution
115
12
7.2
30
1
1.00000
128
ANDERSON SUB, Anderson
Distribution
60
12
2.4
19
3
1
1.00000
129
ANGIOLA SUB, Kings
Distribution
70
12
7.2
16
1
1.00000
130
ANITA SUB, Chico
Distribution
60
12
2.4
38
2
2.00000
131
ANTELOPE SUB, Blackwell Corner
Distribution
70
12
2.4
16
1
1.00000
132
ANTLER SUB, Lakehead
Distribution
60
12
2.4
11
3
1
1.00000
133
APPLE HILL SUB, Camino
Distribution
115
12
7.2
16
1
1.00000
134
APPLE HILL SUB, Camino
Distribution
115
21
7.2
16
1
1.00000
135
ARBUCKLE SUB, ARBUCKLE
Distribution
60
12
7.2
27
4
1
2.00000
136
ARCATA SUB, Arcata
Distribution
60
12
2.4
60
2
2.00000
137
ARVIN SUB, Arvin
Distribution
70
12
2.4
13
3
1
1.00000
138
ASHLAN AVENUE SUB, Fresno
Distribution
230
12
7.2
210
3
3.00000
139
ATASCADERO SUB, Atascadero
Distribution
115
12
7.2
30
1
1.00000
140
ATWATER SUB, Atwater
Distribution
115
12
7.2
90
2
2.00000
141
AUBERRY SUB, Auberry
Distribution
70
12
7.2
25
2
2.00000
142
AVENA SUB, Escalon
Distribution
115
12
16
3
1
1.00000
143
AVENAL SUB, Avenal
Distribution
70
12
16
1
1.00000
144
BAHIA SUB, Benicia
Distribution
230
12
7.2
112
2
2.00000
145
BAIR SUB, Redwood City
Transmission
115
12
7.2
45
1
1.00000
146
BAKERSFIELD SUB, Bakersfield
Distribution
230
21
7.2
225
3
3.00000
147
BANGOR SUB, Bangor
Distribution
60
12
7.2
13
1
1.00000
148
BARTON SUB, Fresno
Distribution
115
12
7.2
120
3
3.00000
149
BASALT SUB, Napa
Distribution
60
12
(e)
2.4
39
4
2.00000
150
BAY MEADOWS SUB, San Mateo
Distribution
115
21
7.2
90
2
2.00000
151
BAY MEADOWS SUB, San Mateo
Distribution
115
12
7.2
75
2
2.00000
152
BAYWOOD SUB, Morro Bay
Distribution
70
12
2.4
16
1
1.00000
153
BEAR VALLEY SUB, Bear Valley
Distribution
70
21
7.2
13
1
1.00000
154
BELL SUB, Auburn
Distribution
115
12
7.2
57
2
2.00000
155
BELLE HAVEN SUB, Menlo Park
Distribution
60
12
(f)
2.4
57
3
3.00000
156
BELLE HAVEN SUB, Menlo Park
Distribution
60
4
2.4
16
6
1
2.00000
157
BELLEVUE SUB, Santa Rosa
Distribution
115
12
7.2
70
3
3.00000
158
BELMONT SUB, Belmont
Distribution
115
12
7.2
135
3
3.00000
159
BERRENDA A SUB,
Distribution
70
4
2.4
16
2
2.00000
160
BIG BASIN SUB, Santa Cruz
Distribution
60
12
11
3
1
1.00000
161
BIG MEADOWS SUB, Greenville
Distribution
60
44
2.4
15
3
1.00000
162
BIOLA SUB, Biola
Distribution
70
12
2.4
20
3
1.00000
163
BLACKWELL SUB, Blackwell Corner
Distribution
70
12
2.4
13
1
1.00000
164
BLUE LAKE SUB, Blue Lake
Distribution
60
12
2.4
13
3
1
1.00000
165
BOGUE SUB, Yuba City
Distribution
115
12
7.2
90
2
2.00000
166
BOLINAS SUB, Boninas
Distribution
60
12
7.2
13
1
1.00000
167
BONITA SUB, Madera
Distribution
70
12
7.2
16
1
1.00000
168
BORDEN SUB, Madera
Transmission
230
12
7.2
30
1
1.00000
169
BOWLES SUB, Bowles
Distribution
70
12
7.2
30
1
1.00000
170
BRENTWOOD SUB, Brentwood
Distribution
230
21
7.2
225
3
3.00000
171
BRITTON SUB, Sunnyvale
Distribution
115
12
120
3
3.00000
172
BRUNSWICK SUB, Grass Valley
Distribution
115
12
7.2
90
3
3.00000
173
BUELLTON SUB, Buellton /93427
Distribution
115
12
7.2
21
2
2.00000
174
BUENA VISTA SUB, Salinas
Distribution
60
12
7.2
76
3
3.00000
175
BULLARD SUB, Fresno
Distribution
115
12
7.2
90
2
2.00000
176
BULLARD SUB, Fresno
Distribution
115
21
7.2
45
1
1.00000
177
BURLINGAME SUB, Burlingame
Distribution
115
21
7.2
30
1
1.00000
178
BUTTE SUB, Chico
Transmission
115
12
7.2
46
2
2.00000
179
CABRILLO SUB, LOMPOC
Distribution
115
12
7.2
11
1
1.00000
180
CADET SUB, Maricopa
Distribution
70
12
20
3
1.00000
181
CAL WATER SUB,
Distribution
115
12
7.2
30
1
1.00000
182
CALAVERAS CEMENT SUB, San Andreas
Distribution
60
12
7.2
15
3
1.00000
183
CALFLAX SUB, Huron
Distribution
70
12
2.4
19
3
1.00000
184
CALIFORNIA AVE SUB, Fresno
Distribution
115
12
7.2
135
3
3.00000
185
CALISTOGA SUB, Calistoga
Distribution
60
12
7.2
21
3
1
1.00000
186
CALPELLA SUB, Calpella
Distribution
115
12
7.2
16
1
1.00000
187
CAMDEN SUB, Riverdale
Distribution
70
12
(g)
2.4
41
2
2.00000
188
CAMP EVERS SUB, Santa Cruz
Distribution
115
21
7.2
90
2
2.00000
189
CAMPHORA SUB, Monterey
Distribution
60
12
7.2
11
1
1.00000
190
CAMPHORA SUB, Monterey
Distribution
60
4
6
3
1
1.00000
191
CANAL SUB, Los Banos
Distribution
70
12
7.2
60
2
2.00000
192
CANTUA SUB, Cantua Creek
Distribution
115
12
24
1
1.00000
193
CAPAY SUB, Orland
Distribution
60
12
2.4
11
6
1.00000
194
CARBONA SUB, Tracy
Distribution
60
12
7.2
37
3
2.00000
195
CARNATION SUB, Bakersfield
Distribution
70
21
7.2
16
1
1.00000
196
CARNERAS SUB, Blackwells Corner
Distribution
70
12
7.2
16
1
1.00000
197
CAROLANDS SUB, Hillsborough
Distribution
60
4
14
2
2.00000
198
CARQUINEZ SUB, Vallejo
Distribution
115
12
2.4
25
2
2.00000
199
CARUTHERS SUB, Fresno
Distribution
70
12
2.4
50
4
2.00000
200
CASSIDY SUB, Madera
Distribution
70
12
2.4
45
1
1.00000
201
CASTRO VALLEY SUB, Castro Valley
Distribution
230
12
90
2
2.00000
202
CASTROVILLE SUB, Castroville
Distribution
115
21
7.2
30
3
1
1.00000
203
CATLETT SUB, Pleasant Grove
Distribution
60
12
39
4
1
2.00000
204
CAWELO B SUB, Famosa
Distribution
70
4
11
1
1.00000
205
CAYETANO SUB, Danville
Distribution
230
21
7.2
45
1
1.00000
206
CAYUCOS SUB, Cayucos
Distribution
70
12
7.2
25
2
2.00000
207
CHANNEL SUB, Stockton
Distribution
60
12
13
1
1.00000
208
CHARCA SUB, Wasco
Distribution
115
12
7.2
41
2
2.00000
209
CHEROKEE SUB, Stockton
Distribution
60
12
7.2
16
1
1.00000
210
CHICO A SUB, Chico
Distribution
60
12
7.2
21
3
1
1.00000
211
CHICO B SUB, Chico
Distribution
115
12
7.2
32
2
2.00000
212
CHOLAME SUB, Cholame/93431
Distribution
70
12
2.4
13
1
1.00000
213
CHOLAME SUB, Cholame/93431
Distribution
70
21
2.4
13
1
1.00000
214
CHOWCHILLA SUB, Chowchilla
Distribution
115
12
7.2
61
2
2.00000
215
CLARK ROAD SUB, Paradise
Distribution
60
12
2.4
11
3
1
1.00000
216
CLARKSVILLE SUB, Clarksville
Distribution
115
21
7.2
135
3
3.00000
217
CLAY SUB, Ione
Distribution
60
12
(h)
2.4
29
2
2.00000
218
CLAYTON SUB, Concord
Distribution
115
21
7.2
135
3
3.00000
219
CLAYTON SUB, Concord
Distribution
115
12
7.2
16
1
1.00000
220
CLEAR LAKE SUB, Finley
Distribution
60
12
2.4
20
6
1
2.00000
221
CLOVERDALE SUB, Cloverdale
Distribution
115
12
7.2
19
3
1
1.00000
222
CLOVIS SUB, Clovis
Distribution
115
12
7.2
90
2
2.00000
223
CLOVIS SUB, Clovis
Distribution
115
21
7.2
45
1
1.00000
224
COALINGA #1 SUB, Coalinga
Distribution
70
12
7.2
27
2
2.00000
225
COALINGA #2 SUB, Coalinga
Distribution
70
12
2.4
21
3
1.00000
226
COARSEGOLD SUB, Coursegold
Distribution
115
21
7.2
61
2
2.00000
227
COLUMBUS SUB, Bakersfield
Distribution
115
12
7.2
59
3
3.00000
228
COLUSA JUNCT SUB, Colusa
Distribution
60
12
7.2
12
1
1.00000
229
COLUSA SUB, Colusa
Distribution
60
12
21
6
1
2.00000
230
CONTRA COSTA SUBSTATION, Antioch
Transmission
230
21
7.2
225
3
3.00000
231
CONTRA COSTA SUBSTATION, Antioch
Transmission
115
21
6.6
42
3
1
1.00000
232
COPPERMINE SUB, Clovis
Distribution
70
12
2.4
20
3
1
1.00000
233
COPUS SUB, Bakersfield
Distribution
70
12
28
4
2.00000
234
CORCORAN SUB, Corcoran
Transmission
115
12
7.2
46
2
2.00000
235
CORDELIA SUB, Cordelia
Distribution
115
12
7.2
45
1
1.00000
236
CORDELIA SUB, Cordelia
Distribution
60
12
2.4
13
3
2
1.00000
237
CORNING SUB, Corning
Distribution
60
12
2.4
58
10
3
2.00000
238
CORONA SUB,
Distribution
115
12
7.2
30
1
1.00000
239
CORRAL SUB, Bellota
Distribution
60
12
7.2
43
2
2.00000
240
CORTINA SUB, Williams
Transmission
115
12
7.2
7
1
1.00000
241
COTATI SUB, Cotati
Distribution
60
12
29
6
1
2.00000
242
COTTLE SUB, Oakdale
Distribution
230
17
130
3
3.00000
243
COTTONWOOD SUB, Cottonwood
Transmission
115
12
7.2
75
2
2.00000
244
COUNTRY CLUB SUB, Stockton
Distribution
60
12
35
3
3.00000
245
COUNTRY CLUB SUB, Stockton
Distribution
60
4
7
1
1.00000
246
CRESSEY SUB, Merced
Distribution
115
21
30
1
1.00000
247
CURTIS SUB, Sonora
Distribution
115
18
90
2
2.00000
248
CUYAMA SUB, Cuyama
Distribution
70
12
19
3
1
1.00000
249
CUYAMA SUB, Cuyama
Distribution
70
21
7.2
16
3
1.00000
250
CYMRIC SUB, McKitrick
Distribution
115
12
7.2
16
1
1.00000
251
DAIRYLAND SUB, Chowchilla
Distribution
115
12
7.2
60
2
2.00000
252
DALY CITY SUB, Daly City
Distribution
115
12
7.2
135
3
3.00000
253
DAVIS SUB, Davis
Distribution
115
12
7.2
135
3
3.00000
254
DEEPWATER SUB, W. Sactramento
Distribution
115
12
7.2
90
2
2.00000
255
DEL MAR SUB, Rocklin
Distribution
60
21
7.2
75
2
2.00000
256
DEL MAR SUB, Rocklin
Distribution
60
12
7.2
16
1
1.00000
257
DEL MONTE SUB, Monterey
Transmission
115
21
7.2
75
2
2.00000
258
DERRICK SUB, Kettleman
Distribution
70
12
2.4
14
1
1.00000
259
DESCHUTES SUB, Palo Cedro
Distribution
60
12
7.2
43
2
2.00000
260
DIAMOND SPRINGS SUB, Placerville
Distribution
115
12
7.2
61
2
2.00000
261
DINUBA SUB, Dinuba
Distribution
70
12
7.2
60
2
2.00000
262
DIVIDE SUB, Orcutt
Transmission
70
12
2.4
11
3
1
1.00000
263
DIVIDE SUB, Orcutt
Transmission
115
12
7.2
30
1
1.00000
264
DIXON LANDING SUB,
Distribution
115
21
7.2
135
3
3.00000
265
DIXON SUB, Dixon
Distribution
60
12
75
2
2.00000
266
DOLAN ROAD SUB, Moss Landing
Distribution
115
12
11
1
1.00000
267
DOS PALOS SUB, Dos Palos
Distribution
70
12
7.2
13
1
1.00000
268
DUMBARTON SUB, Fremont
Distribution
115
12
105
3
3.00000
269
DUNBAR SUB, Glen Ellen
Distribution
60
12
32
6
1
2.00000
270
EAST GRAND SUB, So San Fran.
Distribution
115
12
7.2
180
4
4.00000
271
EAST MARYSVILLE SUB, Marysville,
Distribution
115
12
7.2
25
2
1
2.00000
272
EAST NICOLAUS SUB, E. Nicolaus
Transmission
115
12
16
1
1.00000
273
EAST STOCKTON SUB, Stockton
Distribution
60
12
7.2
16
1
1.00000
274
EAST STOCKTON SUB, Stockton
Distribution
60
4
8
1
1.00000
275
EDENVALE SUB, San Jose
Distribution
115
21
7.2
135
3
3.00000
276
EDENVALE SUB, San Jose
Distribution
115
12
7.2
45
1
1.00000
277
EDES SUB, Oakland
Distribution
115
12
7.2
90
2
2.00000
278
EEL RIVER SUB, Ferndale
Distribution
60
12
7.2
25
4
2.00000
279
EIGHT MILE SUB, Stockton
Distribution
230
21
7.2
90
2
2.00000
280
EL CAPITAN SUB, Snelling
Distribution
115
12
63
2
2.00000
281
EL CAPITAN SUB, Snelling
Distribution
115
21
45
1
1.00000
282
EL CERRITO G SUB, El Cerrito
Distribution
115
12
127
3
3.00000
283
EL NIDO SUB, Merced
Distribution
115
12
7.2
32
2
2.00000
284
EL PATIO SUB, Campbell
Distribution
115
12
7.2
180
4
4.00000
285
EL PECO SUB, Madera
Distribution
70
12
23
2
2.00000
286
ELECTRA SUB,
Distribution
60
12
11
1
1.00000
287
ELK HILLS SUB, Valley Acres
Distribution
70
12
13
1
1.00000
288
ELK SUB, Elk
Distribution
60
12
2.4
11
3
1
1.00000
289
EUREKA A SUB, Eureka
Distribution
60
12
7.2
13
1
1.00000
290
EUREKA E SUB, Eureka
Distribution
60
12
21
3
1
1.00000
291
EVERGREEN SUB, San Jose
Transmission
115
21
7.2
90
2
1
2.00000
292
FAIRHAVEN SUB, Fairhaven
Distribution
60
12
7.2
13
1
1.00000
293
FAIRVIEW SUB, Martinez
Distribution
115
21
12
50
3
1.00000
294
FAIRWAY SUB, Santa Maria
Distribution
115
12
7.2
60
2
2.00000
295
FAMOSO SUB, Famosa
Distribution
115
12
30
1
1.00000
296
FELLOWS SUB, Fellows
Distribution
115
21
60
2
2.00000
297
FIGARDEN SUB, Fresno
Distribution
230
21
7.2
225
3
3.00000
298
FIREBAUGH SUB, Firebaugh
Distribution
70
12
7.2
30
1
1.00000
299
FITCH MOUNTAIN SUB, Healdsburg
Distribution
60
12
7.2
22
2
2.00000
300
FLINT SUB, Auburn
Distribution
115
12
7.2
25
3
1.00000
301
FMC SUB, San Jose
Distribution
115
12
7.2
50
2
2.00000
302
FOOTHILL SUB, SLO
Distribution
115
12
2.4
11
1
1.00000
303
FORESTHILL SUB, Foresthill,
Distribution
60
12
7.2
21
3
1
1.00000
304
FORT BRAGG A SUB, Fort Bragg
Distribution
60
12
60
2
2.00000
305
FORT ORD SUB, Fort Ord
Distribution
60
21
7.2
45
1
1.00000
306
FORT ORD SUB, Fort Ord
Distribution
60
12
2.4
19
3
1
1.00000
307
FRANKLIN SUB, Hercules
Distribution
60
12
7.2
60
2
2.00000
308
FREMONT SUB, Fremont
Distribution
115
12
7.2
105
3
3.00000
309
FRENCH CAMP SUB, Stockton
Distribution
60
12
32
2
2.00000
310
FROGTOWN SUB, Angels Camp
Distribution
115
17
25
4
2.00000
311
FRUITVALE SUB, Bakersfield
Distribution
70
12
2.4
49
4
1
2.00000
312
FULTON SUB, Fulton
Transmission
230
12
7.2
60
2
2.00000
313
GABILAN SUB, Salinas
Distribution
115
12
7.2
16
1
1.00000
314
GALLO SUB, Livingston
Distribution
115
12
25
1
1.00000
315
GANSNER SUB, Quincy
Distribution
60
12
7.2
13
1
1.00000
316
GANSO SUB, Buttonwillow
Distribution
115
12
7.2
16
1
1.00000
317
GARBERVILLE SUB, Garberville
Distribution
60
12
7.2
21
3
1
SVC
1
15
318
GATES SUB, Huron
Transmission
230
12
7.2
45
1
1.00000
319
GATES SUB, Huron
Transmission
115
12
19
3
1.00000
320
GEYSERVILLE SUB, Geyserville
Distribution
60
12
2.4
22
4
2.00000
321
GIFFEN SUB, San Joaquin
Distribution
70
12
2.4
19
3
1.00000
322
GIRVAN SUB, Redding
Distribution
60
12
7.2
16
1
1.00000
323
GLENN SUB, Orland
Transmission
60
12
30
1
1.00000
324
GLENWOOD SUB, Menlo Park
Distribution
60
12
7.2
32
2
2.00000
325
GLENWOOD SUB, Menlo Park
Distribution
60
4
7
1
1.00000
326
GOLDTREE SUB, SLO
Distribution
115
12
7.2
16
1
1.00000
327
GONZALES SUB, Gonzales
Distribution
60
12
22
2
2.00000
328
GOOSE LAKE SUB, Wasco
Distribution
115
12
7.2
27
2
2.00000
329
GRAND ISLAND SUB, Ryde
Distribution
115
21
7.2
81
3
3.00000
330
GRANT SUB, San Lorenzo
Distribution
115
12
7.2
90
2
2.00000
331
GRASS VALLEY SUB, Grass Valley
Distribution
60
12
19
3
1
1.00000
332
GREEN VALLEY SUB, Watsonville
Transmission
115
21
7.2
60
2
2.00000
333
GREENBRAE SUB, Larkspur
Distribution
60
12
7.2
32
2
2.00000
334
GUALALA SUB, Gualala
Distribution
60
12
2.4
12
7
1
2.00000
335
GUERNSEY SUB, Hanford
Distribution
70
12
60
2
2.00000
336
GUSTINE SUB, Gustine
Distribution
60
12
7.2
21
3
3.00000
337
HALF MOON BAY SUB, Half Moon Bay
Distribution
60
12
(i)
2.4
50
5
3.00000
338
HAMMER SUB, Stockton
Distribution
60
12
7.2
90
3
3.00000
339
HAMMONDS SUB, Fresno
Distribution
115
12
16
1
1.00000
340
HARDING SUB, Stockton
Distribution
60
4
13
2
2.00000
341
HARDWICK SUB, Layton
Distribution
70
12
7.2
12
1
1.00000
342
HARRIS SUB, Eureka
Distribution
60
12
7.2
29
2
2.00000
343
HARTER SUB, Yuba City
Distribution
60
12
7.2
60
2
2.00000
344
HARTLEY SUB, Lakeport
Distribution
60
12
7.2
19
2
2.00000
345
HATTON SUB, Carmel Valley
Distribution
60
12
2.4
16
3
1.00000
346
HENRIETTA SUB, Lemoore
Transmission
70
12
2.4
46
2
2.00000
347
HERDLYN SUB, Tracy
Transmission
60
12
2.4
13
1
1.00000
348
HICKS SUB, San Jose
Distribution
230
21
7.2
150
2
2.00000
349
HICKS SUB, San Jose
Distribution
230
12
7.2
90
2
2.00000
350
HIGGINS SUB, Higgins Corner
Distribution
115
12
7.2
77
3
3.00000
351
HIGHLANDS SUB, Clear Lake
Distribution
115
12
7.2
60
2
2.00000
352
HIGHWAY SUB, Petaluma
Distribution
115
12
7.2
90
2
2.00000
353
HOLLISTER SUB, Hollister
Distribution
115
21
7.2
70
2
2.00000
354
HOLLISTER SUB, Hollister
Distribution
60
21
25
1
1.00000
355
HONCUT SUB, Honcut
Distribution
115
12
7.2
16
1
1.00000
356
HOPLAND SUB, Hopland
Transmission
60
12
2.4
13
3
1
1.00000
357
HORSESHOE SUB, Granite Bay
Distribution
115
12
7.2
90
2
2.00000
358
HOWLAND ROAD SUB, Manteca
Distribution
115
12
7.2
16
1
1.00000
359
HUMBOLDT BAY PP SUB, Eureka
Distribution
60
13.8
133
6
2.00000
360
HUMBOLDT BAY PP SUB, Eureka
Distribution
115
13.8
77
3
2.00000
361
HUMBOLDT BAY PP SUB, Eureka
Distribution
60
12
7.2
11
1
1.00000
362
HUMBOLDT BAY PP SUB, Eureka
Distribution
60
2
4
1
1.00000
363
HUMBOLDT BAY PP SUB, Eureka
Distribution
115
2
4
1
1.00000
364
HURON SUB, Huron
Distribution
70
12
2.4
20
3
1.00000
365
IGNACIO SUB, Ignacio
Transmission
115
12
46
2
2.00000
366
IMHOFF SUB, Martinez
Distribution
115
12
7.2
16
1
1.00000
367
IONE SUB, Ione
Distribution
60
12
7.2
13
1
1.00000
368
JACINTO SUB, Willows
Distribution
60
12
7.2
16
1
1.00000
369
JACOBS CORNER SUB, Lemoore
Distribution
70
12
(j)
2.4
29
2
2.00000
370
JAMESON SUB, CORDELIA
Distribution
115
12
7.2
90
2
2.00000
371
JANES CREEK SUB, Arcata
Distribution
60
12
7.2
39
2
2.00000
372
JARVIS SUB, Union City
Distribution
115
12
7.2
105
3
3.00000
373
JESSUP SUB, Anderson
Distribution
115
12
22
1
1.00000
374
JOLON SUB, King City
Distribution
60
12
27
2
2.00000
375
KELSO SUB, Tracy
Distribution
230
12
30
1
1.00000
376
KERMAN SUB, Kerman
Distribution
70
12
7.2
60
2
2.00000
377
KERN OIL SUB, Bakersfield
Distribution
115
12
7.2
135
3
3.00000
378
KERN PP DIST SUB, Bakersfield
Distribution
115
21
7.2
90
2
2.00000
379
KESWICK SUB, Keswick
Distribution
60
12
2.4
11
3
1
1.00000
380
KETTLEMAN HILLS SUB, Kettleman
Distribution
70
12
2.4
11
3
1.00000
381
KING CITY SUB, King City
Distribution
60
12
47
3
3.00000
382
KINGSBURG SUB, Kingsburg
Transmission
115
12
7.2
90
2
2.00000
383
KIRKER SUB, Pittsburg
Distribution
115
21
7.2
135
3
3.00000
384
KONOCTI SUB, Clear Lake
Distribution
60
12
2.4
23
2
2.00000
385
LAKEVIEW SUB, Bakersfield
Distribution
70
12
(k)
2.4
49
4
2.00000
386
LAKEVILLE SUB, Petaluma
Transmission
115
12
7.2
75
2
2.00000
387
LAKEWOOD SUB, Walnut Creek
Distribution
115
21
7.2
215
4
4.00000
388
LAKEWOOD SUB, Walnut Creek
Distribution
115
12
7.2
25
3
1
1.00000
389
LAMMERS SUB, TRACY
Distribution
115
12
7.2
90
2
2.00000
390
LAMONT SUB, Bakersfield
Distribution
115
12
75
2
2.00000
391
LAS GALLINAS A SUB, Las Gallinas
Distribution
115
12
7.2
76
3
3.00000
392
LAS PALMAS SUB, Fresno
Distribution
115
12
7.2
30
1
1.00000
393
LAS POSITAS SUB, Livermore
Transmission
230
21
7.2
165
3
3.00000
394
LAS PULGAS SUB, Redwood City
Distribution
60
4
2.4
14
2
2.00000
395
LAWRENCE SUB, Sunnyvale
Distribution
115
12
7.2
145
5
1
3.00000
396
LE GRAND SUB, Le Grand
Distribution
115
12
7.2
45
1
1.00000
397
LEMOORE SUB, Armonia
Distribution
70
12
2.4
75
2
2.00000
398
LERDO SUB, Bakersfield
Distribution
115
12
7.2
90
2
2.00000
399
LINCOLN SUB, Lincoln
Distribution
115
12
7.2
91
3
3.00000
400
LINDEN SUB, Linden
Distribution
60
12
2.4
19
3
1.00000
401
LIVE OAK SUB, Live Oak
Distribution
60
12
27
2
2.00000
402
LIVERMORE SUB, Livermore
Distribution
60
12
2.4
25
6
2.00000
403
LIVINGSTON SUB, Livingston
Distribution
115
12
7.2
45
1
1.00000
404
LIVINGSTON SUB, Livingston
Distribution
70
12
11
3
1.00000
405
LLAGAS SUB, Gilroy
Distribution
115
21
12
100
3
3.00000
406
LOCKEFORD SUB, Lockeford
Transmission
115
21
7.2
30
1
1
1.00000
407
LOCKHEED #1 SUB, Sunnyvale
Distribution
115
12
7.2
90
2
2.00000
408
LOCKHEED #2 SUB, Sunnyvale
Distribution
115
12
46
2
2.00000
409
LODI SUB, Lodi
Distribution
60
12
2.4
21
3
1
1.00000
410
LODI SUB, Lodi
Distribution
60
4
5
3
1
1.00000
411
LOGAN CREEK SUB, Willows
Distribution
230
21
45
1
1.00000
412
LONETREE SUB, Antioch
Distribution
230
21
7.2
45
1
1.00000
413
LOS ALTOS SUB, Los Altos
Distribution
60
12
51
3
3.00000
414
LOS COCHES SUB, Greenfield
Distribution
60
12
13
3
1
1.00000
415
LOS GATOS SUB, Los Gatos
Distribution
60
12
7.2
32
2
2.00000
416
LOS MOLINOS SUB, Los Molinos
Distribution
60
12
7.2
13
3
1
1.00000
417
LOS OSITOS SUB, Monterey
Distribution
60
21
7.2
43
2
2.00000
418
LOYOLA SUB, Loyola
Distribution
60
12
7.2
21
3
1
1.00000
419
LOYOLA SUB, Loyola
Distribution
60
4
2.4
5
3
1
1.00000
420
LUCERNE SUB, Lucerne
Distribution
115
12
7.2
29
2
2.00000
421
MABURY SUB, San Jose
Distribution
60
12
2.4
19
3
1.00000
422
MABURY SUB, San Jose
Distribution
(c)
60
12
7.2
45
1
1.00000
423
MADERA SUB, Madera
Distribution
70
12
71
7
3.00000
424
MADISON SUB, Madison
Distribution
60
12
7.2
30
1
1.00000
425
MADISON SUB, Madison
Distribution
115
12
21
2
2.00000
426
MAGUNDEN SUB, Bakersfield
Distribution
115
12
7.2
45
1
1.00000
427
MAGUNDEN SUB, Bakersfield
Distribution
115
21
7.2
45
1
1.00000
428
MALAGA SUB, Fresno
Distribution
115
12
7.2
105
3
3.00000
429
MANCHESTER SUB, Fresno
Distribution
115
12
7.2
135
3
3.00000
430
MANTECA SUB, Manteca
Transmission
115
17
135
8
1
4.00000
431
MARICOPA SUB, Maricopa
Distribution
70
12
2.4
11
3
1.00000
432
MARIPOSA SUB, Mariposa
Distribution
70
21
32
2
2.00000
433
MARTELL SUB, Martell
Distribution
60
12
2.4
13
3
1
1.00000
434
MARYSVILLE SUB, Marysville
Distribution
60
12
49
4
1
2.00000
435
MAXWELL SUB, Maxwell
Distribution
60
12
43
4
1
2.00000
436
MCARTHUR SUB, McArthur
Distribution
60
12
2.4
11
3
1
1.00000
437
MCCALL SUB, Selma
Transmission
115
12
7.2
90
2
2.00000
438
MCDONALD-MCDONALDISLAND SUB, Stockton
Distribution
60
4
2.4
21
2
2.00000
439
MCFARLAND SUB, McFarland
Distribution
70
12
7.2
32
2
2.00000
440
MCKEE SUB, San Jose
Distribution
115
12
7.2
105
3
3.00000
441
MCKITTRICK SUB, MCKITTRICK
Distribution
70
12
13
4
1
1.00000
442
MCMULLIN SUB, Fresno
Distribution
230
12
7.2
45
1
1.00000
443
MEADOW LANE SUB, Concord
Distribution
115
21
7.2
170
3
3.00000
444
MENDOCINO SUB, Redwood Valley
Transmission
60
12
2.4
5
3
1
1.00000
445
MENDOTA SUB, Mendota
Transmission
115
12
7.2
30
1
1.00000
446
MENLO SUB, Menlo Park
Distribution
60
12
7.2
32
2
2.00000
447
MENLO SUB, Menlo Park
Distribution
60
4
18
2
2.00000
448
MERCED SUB, Merced
Transmission
115
12
7.2
45
1
1.00000
449
MERCED SUB, Merced
Transmission
115
21
7.2
45
1
1.00000
450
MERIDIAN SUB, Meridian
Distribution
60
12
21
3
1
1.00000
451
MESA SUB, Nipomo
Transmission
230
12
45
1
1.00000
452
METTLER SUB, Stockton
Distribution
60
12
11
1
1.00000
453
MIDDLETOWN SUB, Middletown
Distribution
60
12
7.2
34
4
1
2.00000
454
MIDWAY SUB, Buttonwillow
Transmission
115
12
7.2
23
2
2.00000
455
MILLBRAE SUB, Millbrae
Transmission
115
12
60
2
2.00000
456
MILLBRAE SUB, Millbrae
Transmission
60
4
6
3
1
1.00000
457
MILPITAS SUB, Milpitas
Distribution
115
21
7.2
90
2
2.00000
458
MILPITAS SUB, Milpitas
Distribution
115
12
7.2
75
2
2.00000
459
MIRABEL SUB, Forestville
Distribution
60
12
11
1
1.00000
460
MI-WUK SUB, Sugarpine
Distribution
115
17
14
3
1
1.00000
461
MOLINO SUB, Sebastopol
Distribution
60
12
7.2
43
2
2.00000
462
MONROE SUB, Santa Rosa
Distribution
115
21
7.2
90
2
2.00000
463
MONROE SUB, Santa Rosa
Distribution
115
12
7.2
45
1
1.00000
464
MONTAGUE SUB, San Jose
Distribution
115
21
7.2
135
3
3.00000
465
MONTE RIO SUB, Monte Rio
Distribution
60
12
7.2
29
2
2.00000
466
MONTEREY SUB, Monterey
Distribution
60
4
11
3
1
1.00000
467
MORAGA SUB, Orinda
Transmission
115
12
45
1
1.00000
468
MORGAN HILL SUB, Morgan Hill
Distribution
115
21
7.2
120
3
3.00000
469
MORMON SUB, Stockton
Distribution
60
12
7.2
30
1
1.00000
470
MORRO BAY PP SWYD, Morro Bay
Transmission
115
12
7.2
16
1
1.00000
471
MOSHER SUB, Stockton
Distribution
60
21
7.2
105
3
3.00000
472
MOUNTAIN VIEW SUB, Mt. View
Distribution
115
12
7.2
115
3
2.00000
473
MT. EDEN SUB, Hayward
Distribution
115
12
7.2
135
3
2.00000
474
MT. QUARRIES SUB, Cool
Distribution
60
12
7.2
16
1
1.00000
475
NAPA SUB, Napa
Distribution
60
12
79
5
3.00000
476
NARROWS SUB,
Distribution
60
21
7.2
30
1
1.00000
477
NEWARK DIST SUB, Fremont
Distribution
230
21
7.2
150
2
2.00000
478
NEWARK SUB, Fremont
Transmission
115
12
7.2
90
2
2.00000
479
NEWBURG SUB, Fortuna
Distribution
60
12
2.4
20
4
1
2.00000
480
NEWHALL SUB, Firebaugh
Distribution
115
12
7.2
29
2
2.00000
481
NEWMAN SUB, Newman
Distribution
60
12
7.2
41
4
2.00000
482
NORCO SUB, Bakersfield
Distribution
115
12
7.2
16
1
1.00000
483
NORD SUB, Chico
Distribution
115
12
7.2
32
2
2.00000
484
NORTECH SUB, San Jose
Distribution
115
21
7.2
90
2
2.00000
485
NORTH DUBLIN SUB, Pleasanton
Distribution
230
21
12
45
1
1.00000
486
NORTH TOWER SUB, Vallejo
Distribution
115
12
7.2
90
2
2.00000
487
NOTRE DAME SUB, Chico
Distribution
115
12
7.2
45
1
1.00000
488
NOVATO SUB, Novato
Distribution
60
12
7.2
23
2
2.00000
489
OAKHURST SUB, Oakhurst
Distribution
115
12
2.4
43
3
2.00000
490
OAKLAND C (OAKLAND PP) SUB, Oakland
Distribution
115
12
7.2
195
4
4.00000
491
OAKLAND D SUB, Oakland
Distribution
115
12
7.2
175
4
4.00000
492
OAKLAND J SUB, Oakland
Distribution
115
12
7.2
120
3
3.00000
493
OAKLAND K (CLAREMONT) SUB, Oakland
Distribution
115
12
6.6
38
3
1
1.00000
494
OAKLAND L SUB, Oakland
Distribution
115
12
7.2
135
3
3.00000
495
OAKLAND X SUB, Oakland
Distribution
115
12
7.2
90
3
3.00000
496
OCEANO SUB, Oceano
Distribution
115
12
7.2
75
2
2.00000
497
OILFIELDS SUB, San Ardo
Distribution
60
12
42
6
1
2.00000
498
OLD KEARNEY SUB, Fresno
Distribution
70
12
13.2
31
4
2.00000
499
OLD RIVER SUB, Knob Hill
Distribution
70
12
2.4
16
1
1.00000
500
OLD RIVER SUB, Knob Hill
Distribution
(d)
70
12
7.2
45
1
1.00000
501
OLETA SUB, Plymouth
Distribution
60
12
2.4
18
4
2.00000
502
OLIVEHURST SUB, Olivehurst
Distribution
115
12
7.2
60
2
2.00000
503
OREGON TRAIL SUB, Redding
Distribution
115
12
7.2
16
1
1.00000
504
OREGON TRAIL SUB, Redding
Distribution
60
12
2.4
6
3
1.00000
505
ORLAND B SUB, Orland
Distribution
60
12
2.4
25
7
2.00000
506
ORO FINO SUB, Magalia
Distribution
60
12
2.4
11
1
1.00000
507
ORO LOMA SUB, Dos Palos
Transmission
70
12
2.4
22
3
1.00000
508
ORO LOMA SUB, Dos Palos
Transmission
115
12
45
1
1.00000
509
OROSI SUB, Orosi
Distribution
70
12
7.2
41
2
2.00000
510
OROVILLE SUB, Oroville
Distribution
60
12
7.2
25
2
2.00000
511
OROVILLE SUB, Oroville
Distribution
60
4
2.4
5
3
1
1.00000
512
ORTIGA SUB, Los Banos
Distribution
70
12
2.4
16
1
1.00000
513
PACIFICA SUB, Pacifica
Distribution
60
12
23
2
2.00000
514
PALMER SUB, Sisquat
Distribution
115
12
7.2
11
1
1.00000
515
PANAMA SUB, Bakersfield
Distribution
70
21
7.2
45
1
1.00000
516
PANOCHE SUB, Mendota
Transmission
230
12
7.2
30
1
1.00000
517
PANORAMA SUB, Anderson
Distribution
115
12
30
1
1.00000
518
PARADISE SUB, Paradise
Distribution
60
12
7.2
45
1
1.00000
519
PARADISE SUB, Paradise
Distribution
115
12
45
1
1.00000
520
PARKWAY SUB, Vallejo
Distribution
230
12
7.2
30
1
1.00000
521
PARLIER SUB, Parlier
Distribution
115
12
7.2
45
1
1.00000
522
PASO ROBLES SUB, Paso Robles
Distribution
70
12
(l)
2.4
90
3
3.00000
523
PAUL SWEET SUB, Santa Cruz
Distribution
115
21
7.2
135
3
SVC
1
60
524
PEABODY SUB, Fairfield
Distribution
230
21
7.2
195
3
3.00000
525
PEACHTON SUB, Gridley
Distribution
60
12
2.4
14
6
1
2.00000
526
PEASE SUB, Tierra Buena
Transmission
115
12
50
2
2.00000
527
PENNGROVE SUB, Penngrove
Distribution
115
12
13
1
1.00000
528
PENRYN SUB, Penryn
Distribution
60
12
7.2
61
2
2.00000
529
PEORIA SUB, Jamestown
Distribution
115
18
58
4
2.00000
530
PETALUMA C SUB, Petaluma
Distribution
60
12
57
5
1
3.00000
531
PIERCY SUB, San Jose
Distribution
115
21
7.2
45
1
1.00000
532
PINE GROVE SUB, Pine Grove
Distribution
60
12
2.4
22
4
2.00000
533
PINEDALE SUB, FRESNO
Distribution
115
21
7.2
135
3
3.00000
534
PLACER SUB, Auburn
Transmission
115
12
41
4
1
2.00000
535
PLACERVILLE SUB, Placerville
Distribution
115
12
7.2
30
1
1.00000
536
PLACERVILLE SUB, Placerville
Distribution
115
21
30
1
1.00000
537
PLAINFIELD SUB, Davis
Distribution
60
12
(m)
2.4
39
2
2.00000
538
PLEASANT GROVE SUB, Pleasant Grove
Distribution
60
21
7.2
135
3
3.00000
539
PLUMAS SUB, Wheatland
Distribution
60
21
7.2
45
1
1.00000
540
PLUMAS SUB, Wheatland
Distribution
60
12
7.2
13
1
1.00000
541
POINT MORETTI SUB, Davenport
Distribution
60
12
2.4
11
1
1.00000
542
POINT PINOLE SUB, Richmond
Distribution
115
12
6.6
16
1
1.00000
543
POSO MOUNTAIN SUB, Kern
Distribution
115
21
65
2
1.00000
544
PRUNEDALE SUB, Prunedale
Distribution
115
12
7.2
32
2
2.00000
545
PUEBLO SUB, Napa
Distribution
115
12
45
1
StatCom
2
8
546
PUEBLO SUB, Napa
Distribution
115
21
45
1
1.00000
547
PURISIMA SUB, Lompoc
Distribution
115
12
7.2
11
1
1.00000
548
PUTAH CREEK SUB, Winters
Distribution
115
12
32
2
2.00000
549
RACE TRACK SUB, Jamestown
Distribution
115
17
16
1
1.00000
550
RADUM SUB, Pleasanton
Distribution
60
12
25
6
2.00000
551
RAINBOW SUB, Sanger
Distribution
115
12
7.2
30
1
1.00000
552
RALSTON SUB, Belmont
Distribution
60
12
16
4
2.00000
553
RANCHERS COTTON SUB, Fresno
Distribution
115
12
7.2
16
1
1.00000
554
RAWSON SUB, Red Bluff
Distribution
60
12
2.4
19
3
1.00000
555
RED BLUFF SUB, Red Bluff
Distribution
60
12
2.4
50
5
3.00000
556
REDBUD SUB, Clearlake Oaks
Distribution
115
12
7.2
23
3
2.00000
557
REDWOOD CITY SUB, Redwood City
Distribution
60
12
7.2
70
5
3.00000
558
REDWOOD CITY SUB, Redwood City
Distribution
60
4
14
3
1.00000
559
REEDLEY SUB, Reedley
Transmission
115
12
7.2
30
1
1.00000
560
REEDLEY SUB, Reedley
Transmission
70
12
2.4
30
1
1.00000
561
RENFRO SUB, BAKERSFIELD
Distribution
115
12
7.2
90
2
2.00000
562
RESEARCH SUB, San Ramon
Distribution
230
21
7.2
45
1
1.00000
563
RESERVATION ROAD SUB, Salinas
Distribution
60
12
2.4
11
1
1.00000
564
RICE SUB, Princeton
Distribution
60
12
4.16
14
2
2.00000
565
RICHMOND R SUB, Richmond
Distribution
115
12
7.2
90
2
2.00000
566
RINCON SUB, Santa Rosa
Distribution
115
12
32
2
2.00000
567
RIO BRAVO SUB, Shafter
Distribution
115
12
7.2
64
4
2.00000
568
RIO DELL SUB, Rio Dell
Distribution
60
12
11
3
1.00000
569
RIPON SUB, Ripon
Distribution
115
17
73
2
2.00000
570
RISING RIVER SUB, Cassell,
Distribution
60
12
2.4
11
3
1
1.00000
571
RIVER OAKS SUB, San Jose
Distribution
115
21
7.2
90
2
2.00000
572
RIVERBANK SUB, Escalon
Distribution
115
12
73
4
1
2.00000
573
ROB ROY SUB, Watsonville
Distribution
115
21
7.2
23
1
1.00000
574
ROCKLIN SUB, Rocklin
Distribution
60
12
7.2
27
4
1
2.00000
575
ROSEDALE SUB, Bakersfield
Distribution
115
12
7.2
30
1
1.00000
576
ROSSMOOR SUB, Walnut Creek
Distribution
230
12
90
2
2.00000
577
ROUGH & READY ISLAND SUB, Stockton
Distribution
60
12
7.2
16
1
1.00000
578
SALINAS SUB, Salinas
Transmission
115
12
7.2
90
2
2.00000
579
SALMON CREEK SUB, Bodega Bay
Distribution
60
12
2.4
11
3
1
1.00000
580
SAN ARDO SUB, San Ardo
Distribution
60
12
11
3
1
1.00000
581
SAN BENITO SUB, San Benito
Distribution
115
21
7.2
30
1
1.00000
582
SAN BERNARD SUB, Lamont
Distribution
70
12
2.4
19
3
1.00000
583
SAN CARLOS SUB, San Carlos
Distribution
60
12
7.2
29
2
2.00000
584
SAN CARLOS SUB, San Carlos
Distribution
60
4
2.4
12
3
1
1.00000
585
SAN FRAN A (POTRERO PP) SUB, San Francisco
Transmission
115
12
7.2
186
3
3.00000
586
SAN FRAN H (MARTIN) SUB, Daly City
Transmission
115
12
180
4
4.00000
587
SAN FRAN P-HUNTERS POINT SUB, San Francisco
Distribution
115
12
98
2
2.00000
588
SAN FRAN X (MISSION) SUB, San Francisco
Distribution
115
12
7.2
375
5
5.00000
589
SAN FRAN Y (LARKIN) SUB, San Francisco
Distribution
115
12
7.2
450
6
6.00000
590
SAN FRAN Z (Embarcadero), San Francisco
Distribution
230
34.5
7.2
345
3
3.00000
591
SAN JOAQUIN SUB, San Joaquin
Distribution
70
12
7.2
18
2
2.00000
592
SAN JOSE A SUB, San Jose
Distribution
115
4
7.2
40
2
3.00000
593
SAN JOSE A SUB, San Jose
Distribution
115
12
30
1
1.00000
594
SAN JOSE B SUB, San Jose
Distribution
115
12
7.2
180
4
2.00000
595
SAN LEANDRO U SUB, San Leandro
Distribution
115
12
160
4
4.00000
596
SAN LUIS OBISPO SUB, SLO
Transmission
115
12
7.2
135
3
3.00000
597
SAN MATEO SUB, San Mateo
Transmission
115
21
45
1
1.00000
598
SAN MATEO SUB, San Mateo
Transmission
60
4
13
3
1
1.00000
599
SAN MIGUEL SUB, San Miguel
Distribution
70
12
7.2
16
1
1.00000
600
SAN PABLO SUB, Richmond
Distribution
115
12
7.2
45
1
1.00000
601
SAN RAFAEL SUB, San Rafael
Distribution
115
12
120
3
3.00000
602
SAN RAMON SUB, San Ramon
Transmission
230
21
12
300
4
4.00000
603
SANGER SUB, Fresno
Transmission
115
12
7.2
60
2
2.00000
604
SANTA MARIA SUB, Santa Maria
Distribution
115
12
7.2
90
2
2.00000
605
SANTA NELLA SUB, Santa Nella
Distribution
70
12
2.4
27
2
2.00000
606
SANTA RITA SUB, Dos Palos
Distribution
70
12
2.4
12
3
1.00000
607
SANTA ROSA A SUB, Santa Rosa
Distribution
115
12
7.2
135
3
3.00000
608
SANTA YNEZ SUB, Santa Maria
Distribution
115
12
7.2
41
2
2.00000
609
SARATOGA SUB, Saratoga
Distribution
230
12
7.2
157
3
3.00000
610
SAUSALITO SUB, Sausalito
Distribution
60
12
2.4
21
3
1
1.00000
611
SAUSALITO SUB, Sausalito
Distribution
60
4
5
3
1
1.00000
612
SCHINDLER SUB, Five Points
Transmission
115
12
7.2
60
2
2.00000
613
SEMITROPIC SUB, Wasco
Transmission
115
12
7.2
30
1
1.00000
614
SERRAMONTE SUB, Daly City
Distribution
115
12
13
1
1.00000
615
SHAFTER SUB, Shafter
Distribution
115
12
7.2
72
4
1
2.00000
616
SHARON SUB, Chowchilla
Distribution
115
12
11
1
1.00000
617
SHEPARD SUB, Clovis
Distribution
115
21
7.2
45
1
1.00000
618
SHINGLE SPRINGS SUB, Shingle Springs
Distribution
115
21
7.2
61
2
2.00000
619
SHINGLE SPRINGS SUB, Shingle Springs
Distribution
115
12
7.2
16
1
1.00000
620
SHREDDER SUB, Redwood City
Distribution
115
4
6.6
15
3
1
1.00000
621
SILVERADO SUB, St. Helena
Distribution
115
21
60
2
2.00000
622
SISQUOC SUB, Orcutt
Distribution
115
12
7.2
32
2
2.00000
623
SMYRNA SUB, Wasco
Distribution
115
12
7.2
49
4
2.00000
624
SNEATH LANE SUB, San Bruno
Distribution
60
12
2.4
19
6
2.00000
625
SOBRANTE SUB, Orinda
Transmission
115
12
7.2
30
1
1.00000
626
SOLEDAD SUB, Soledad
Transmission
60
12
11
1
1.00000
627
SONOMA A SUB, Sonoma
Distribution
115
12
60
2
2.00000
628
SOUTH BAY #1 & #2 SUB, Tracy
Distribution
60
4
25
3
3.00000
629
SPANISH CREEK SUB,
Distribution
60
44
19
1
1.00000
630
SPENCE SUB, Salinas
Distribution
60
12
13
3
1
2.00000
631
SRI SUB, Menlo Park
Distribution
60
12
13
1
1.00000
632
STAFFORD SUB, Novato
Distribution
60
12
25
2
2.00000
633
STAGG SUB, Stockton
Transmission
230
21
7.2
150
2
2.00000
634
STAGG SUB, Stockton
Transmission
60
12
2.4
51
4
1
2.00000
635
STELLING SUB, Cupertino
Distribution
115
12
7.2
105
3
2.00000
636
STILLWATER STA SUB, Project City
Distribution
60
12
2.4
11
3
1
1.00000
637
STOCKDALE SUB, Bakersfield
Distribution
230
21
7.2
225
3
3.00000
638
STOCKDALE SUB, Bakersfield
Distribution
115
12
7.2
75
2
2.00000
639
STOCKTON A SUB, Stockton
Distribution
115
12
105
3
3.00000
640
STOCKTON A SUB, Stockton
Distribution
60
4
22
6
1.00000
641
STONE CORRAL SUB, Woodlake
Distribution
70
12
2.4
17
2
2.00000
642
STONE SUB, San Jose
Distribution
115
12
7.2
45
1
1.00000
643
STOREY SUB, Madera
Distribution
230
12
7.2
90
2
2.00000
644
STROUD SUB, Helm
Distribution
70
12
2.4
21
3
1
1.00000
645
SUISUN SUB, Fairfield
Distribution
115
12
7.2
120
3
3.00000
646
SUNOL SUB, Sunol
Distribution
60
12
7.2
13
1
1.00000
647
SWIFT SUB, San Jose
Distribution
115
21
7.2
135
3
3.00000
648
SYCAMORE CREEK SUB, Chico
Distribution
115
12
90
3
3.00000
649
TAFT SUB, Taft
Transmission
115
12
7.2
27
2
2.00000
650
TAMARACK SUB, Soda Springs
Distribution
60
12
7.2
13
1
1.00000
651
TASSAJARA SUB, Danville
Distribution
230
21
7.2
225
3
3.00000
652
TEJON SUB, Leboc
Distribution
70
12
(n)
2.4
49
4
2.00000
653
TEMBLOR SUB, McKittrick
Distribution
115
12
2.4
21
3
1
1.00000
654
TEMPLETON SUB, TEMPLETON
Transmission
230
21
7.2
90
2
2.00000
655
TEVIS SUB, Oildale
Distribution
115
21
7.2
90
2
2.00000
656
TIDEWATER SUB, Martinez
Distribution
230
21
150
2
2.00000
657
TIVY VALLEY SUB, Fresno
Distribution
70
12
7.2
13
1
1.00000
658
TRACY SUB, Tracy
Distribution
115
12
7.2
121
4
4.00000
659
TRES VIAS SUB, Oroville
Distribution
60
12
7.2
16
1
1.00000
660
TRIMBLE SUB, San Jose
Distribution
115
12
7.2
90
2
2.00000
661
TRIMBLE SUB, San Jose
Distribution
115
21
7.2
90
2
2.00000
662
TULARE LAKE SUB, Kettleman
Distribution
70
12
2.4
24
4
2
2.00000
663
TULUCAY SUB, Napa
Transmission
60
12
7.2
30
1
1.00000
664
TUPMAN SUB, Tupman
Distribution
115
12
7.2
61
2
2.00000
665
TWISSELMAN SUB, Blackwell Corners
Distribution
70
12
7.2
32
2
2.00000
666
TYLER SUB, Red Bluff
Distribution
60
12
2.4
19
6
2.00000
667
UKIAH SUB, Ukiah
Distribution
115
12
7.2
29
2
2.00000
668
URICH SUB, Martinez
Distribution
60
4
10
3
1
1.00000
669
VACA DIXON SUB, Vacaville
Transmission
115
12
7.2
105
3
3.00000
670
VACAVILLE SUB, Vacaville
Distribution
115
12
7.2
120
3
3.00000
671
VALLEY HOME SUB, Valley Home
Distribution
60
17
6
3
1
1.00000
672
VALLEY HOME SUB, Valley Home
Distribution
115
17
30
1
1.00000
673
VALLEY VIEW SUB, El Sobrante
Distribution
115
12
29
2
2.00000
674
VASCO SUB, Livermore
Distribution
60
12
17
6
2.00000
675
VASONA SUB, Los Gatos
Distribution
230
12
7.2
90
2
4.00000
676
VICTOR SUB, Lodi
Distribution
60
12
2.4
30
1
1.00000
677
VIEJO SUB, Monterey
Distribution
60
21
7.2
60
2
2.00000
678
VIERRA SUB, Lathrop
Distribution
115
17
7.2
90
2
2.00000
679
VINEYARD SUB, Pleasanton
Distribution
230
21
7.2
150
2
1
2.00000
680
VOLTA #1PH SUB, Shingletown
Distribution
60
12
2.4
21
3
1
1.00000
681
WAHTOKE SUB, Reedley
Distribution
115
12
7.2
60
2
2.00000
682
WASCO SUB, Wasco
Distribution
70
12
2.4
20
3
1.00000
683
WATERLOO SUB, Stockton
Distribution
60
12
2.4
11
1
1.00000
684
WATSONVILLE SUB, Watsonville
Distribution
60
12
7.2
16
1
1.00000
685
WATSONVILLE SUB, Watsonville
Distribution
60
4
8
1
1.00000
686
WEBER SUB, Stockton
Transmission
60
12
7.2
50
2
2.00000
687
WEBER SUB, Stockton
Transmission
230
12
7.2
90
2
2.00000
688
WEEDPATCH SUB, Weedpatch
Distribution
70
12
7.2
30
1
1.00000
689
WELLFIELD SUB, Lamont
Distribution
70
12
2.4
24
4
2.00000
690
WEST FRESNO SUB, Fresno
Distribution
115
12
7.2
135
3
3.00000
691
WEST LANE SUB, Stockton
Distribution
60
12
7.2
30
1
1.00000
692
WEST SACRAMENTO SUB, WEST SACRAMENTO
Distribution
115
12
7.2
105
3
3.00000
693
WESTLEY SUB, Westley
Distribution
60
12
2.4
29
2
2.00000
694
WESTPARK SUB, Bakersfield
Distribution
115
12
7.2
105
3
3.00000
695
WHEATLAND SUB, Wheatland
Distribution
60
12
7.2
44
4
1
2.00000
696
WHEELER RIDGE SUB, Bakersfield
Transmission
70
12
7.2
30
1
1.00000
697
WHISMAN SUB, Mt. View
Distribution
115
12
7.2
105
3
3.00000
698
WILLIAMS SUB, Williams
Distribution
60
12
7.2
27
2
2.00000
699
WILLITS A SUB, Willits
Distribution
60
12
2.4
19
3
1
1.00000
700
WILLOW CREEK SUB, Willow Creek
Distribution
60
12
2.4
13
3
1
1.00000
701
WILLOW PASS SUB, Pittsburg
Distribution
115
21
7.2
30
1
1.00000
702
WILLOW PASS SUB, Pittsburg
Distribution
60
12
2.4
11
3
1
1.00000
703
WILLOWS A SUB, Willows
Distribution
60
12
14
3
1
1.00000
704
WILSON SUB, Merced
Transmission
115
12
14
1
1.00000
705
WINDSOR SUB, Windsor
Distribution
60
12
30
1
1.00000
706
WINTERS SUB, Winters
Distribution
60
12
13
1
1.00000
707
WOLFE SUB, Cupertino
Distribution
115
12
120
3
3.00000
708
WOODCHUCK SUB, Wilson Village
Distribution
70
21
23
3
1.00000
709
WOODLAND SUB, Woodland
Distribution
115
12
7.2
135
3
3.00000
710
WOODSIDE SUB, Woodside
Distribution
60
12
60
2
2.00000
711
WOODWARD SUB, Fresno
Distribution
115
21
7.2
135
3
3.00000
712
WRIGHT SUB, Los Banos
Distribution
70
12
2.4
13
1
1.00000
713
WYANDOTTE SUB, Oroville
Distribution
115
12
7.2
120
3
3.00000
714
ZACA SUB, Santa Maria
Distribution
115
12
7.2
11
1
1.00000
715
ZAMORA SUB, Zamora
Distribution
115
12
27
2
2.00000
716
(a)
Rounding issues in column f
-57
717
Total Distribution and Transmission Substations
82,440
18,872.1
4,089.56
96173
1780
159
13
641
718
(b)
Transmission only Substations
24,120
10,990
1,342.2
64915
359
57
719
Combined Dist Subs < 10MVA (129 substations)
675
331
54


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SubstationNameAndLocation

The original entries in column f were in two decimal places, which the FERC software rounds automatically to whole numbers. The entry here is an adjustment to present the correct total.

 

(b) Concept: SubstationNameAndLocation

Substation voltage classes are listed separately for each substation. Therefore, there will be multiple line entries for substations having more than one voltage class. Substations having combined total capacity of =>10 MVA are listed individually. Substations with less than 10 MVA capacity are lumped together in one line item. All transmission substations are =>10 MVA.

 

There are 92 Transmission Substations and 605 Distribution Substations. This represents a total of 697 physical transmission and distribution substations (92+605=697). All transmission and distribution substations are unattended.

 

Any substation that has a transmission-to-transmission transformation (Primary voltage >=60kV and secondary voltage >= 60kV) is defined as a transmission station, regardless of the number of distribution assets in the station. Hence, substations with both transmission and distribution (secondary voltage <60 kV) transformers are characterized as Transmission in the list. There are 59 Transmission Substations with both transmission and distribution transformers; one of them <10MVA. There are 664 substations with distribution transformer banks. (605+59 = 664)

(c) Concept: PrimaryVoltageLevel

60 or 115

(d) Concept: PrimaryVoltageLevel

70 or 115

(e) Concept: TertiaryVoltageLevel

2.4 & 7.2

(f) Concept: TertiaryVoltageLevel

2.4 & 7.2

(g) Concept: TertiaryVoltageLevel

2.4 & 7.2

(h) Concept: TertiaryVoltageLevel

2.4 & 7.2

(i) Concept: TertiaryVoltageLevel

2.4 & 7.2

(j) Concept: TertiaryVoltageLevel

2.4 & 7.2

(k) Concept: TertiaryVoltageLevel

2.4 & 7.2

(l) Concept: TertiaryVoltageLevel

2.4 & 7.2

(m) Concept: TertiaryVoltageLevel

2.4 & 7.2

(n) Concept: TertiaryVoltageLevel

2.4 & 7.2


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
  1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
  2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not attempt to include or aggregate amounts in a nonspecific category such as "general".
  3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Line No.
Description of the Good or Service
(a)
Name of Associated/Affiliated Company
(b)
Account(s) Charged or Credited
(c)
Amount Charged or Credited
(d)
1
Non-power Goods or Services Provided by Affiliated
2
PG&E Corporation
3
(a)
Corporate A&G Allocations
94,248,645
4
Total - Administrative & General Expenses
94,248,645
5
Rent Expense
Eureka Energy Company
321,288
6
Total Non-power Goods/Srv.provided by Affilia
94,569,933
19
20
Non-power Goods or Services Provided for Affiliated
21
PG&E Corporation
22
ACCOUNTING
536,406
23
ADMINISTRATION
509,322
24
AFFILIATE RULES COMPLIANCE SUPPORT
24,463
25
BANKING SERVICES
33,980
26
BOD EXPENSES
23
27
BUSINESS PLANNING SERVICES
26,436
28
COMPLIANCE & ETHICS SUPPORT
8,469
29
CONSULTING SERVICES
5,656
30
CORPORATE SECRETARY SUPPORT
1,885
31
CORPORATE SUSTAINABILITY SUPPORT
242,594
32
FINANCIAL FORECASTING AND ANALYSIS
56,932
33
FLEET SERVICES
27,617
34
HUMAN RESOURCES SUPPORT
72,382
35
INFORMATION TECHNOLOGY
450,881
36
INSURANCE SUPPORT
13,577
37
INTERNAL AUDIT SERVICES
6,001
38
INVESTOR RELATIONS SUPPORT
9,802
39
LEGAL
98,874
40
MISC EXPENSE
41
41
REAL ESTATE AND FACILITY
667,510
42
SECURITY SUPPORT
327,578
43
SOURCING SUPPORT
122,355
44
STRATEGIC ANALYSIS SUPPORT
47,456
45
TAX SERVICES
89,462
46
EMPLOYEE TRANSFER FEE
351,426
47
INTEREST
40,201
48
Total - A&G Direct Charges to PG&E Corp
3,771,329
49
FUELCO
50
ACCOUNTING
18,032
51
CFO SUPPORT
6,011
52
FUEL PURCHASING SUPPORT
426,283
53
LEGAL
1,208
54
SUPPLY CHAIN SUPPORT
9,051
55
Total - A&G Direct Charges to FUELCO
460,585
56
TOTAL NON-POWER GOODS/SRV PROVIDED
57
FOR AFFILIATES
4,231,914
42


Name of Respondent:

PACIFIC GAS AND ELECTRIC COMPANY
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

04/16/2019
Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfNonPowerGoodOrService

1. Allocation of Corporation cost center costs were based on one of the following methods:

(A) 3-Factor Method

Simple Average of the following ratios:

(a) Affiliate Assets/Total Consolidated Assets

(b) Affiliate Operating Expenses less Fuel purchase costs/Total Consolidated Operating Expenses less Fuel

Purchase Cost

(c) Affiliate Headcount/Total Consolidated Headcount

(B) Capitalization

Affiliate Capitalization/Total Consolidated Capitalization

(C) Headcount

Affiliate Headcount/Total Consolidated Headcount

 

For 2018, the Corporation’s A&G Allocation Rate is rounded to 99% based on the calculation from three methodologies above.

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