1 3 4 6 8 9 10 11 12 14 15 17 19 21 22 24 26 1 3 4 5 6 8 9 10 11 13 14 15 17 18 1 1 101 201 2 102 202 3 103 203 4 104 204 5 105 205 6 106 206 1002 1102 1202 1402 1502 1302 1602 3 103 203 303 403 503 603 703 803 903 1003 1103 1203 1303 1403 1503 1603 4 104 204 304 404 504 604 704 804 904 1004 1104 1204 1304 1404 1504 1604 5 105 205 305 405 505 605 705 805 1126 1203 1014 1303 1114 1226 1326 1403 1214 1526 1503 1314 1426 1603 1414 1703 1514 1626 27 1803 1614 1903 15 127 227 4 115 327 104 215 427 204 315 304 415 527 627 404 515 504 615 727 827 604 715 927 704 815 1027 804 915 904 1015 1127 1227 1004 1215 1104 1315 1327 1427 1204 1415 1527 1304 1515 28 1404 1115 1504 1615 128 228 1604 16 1704 116 328 428 1804 216 528 1904 316 628 5 416 105 516 728 828 205 616 305 716 928 1028 405 816 1128 505 916 1228 605 1016 705 1116 1328 1428 805 1216 905 1316 1528 29 1005 1516 129 1105 1416 229 1205 1616 1305 17 329 429 1405 117 1505 217 529 629 1605 317 729 1705 417 829 1805 517 929 1905 617 6 817 1029 1129 106 917 1313 1413 1513 1613 1713 1813 14 114 214 314 414 514 614 714 814 914 1014 1114 1214 1314 1414 1514 1614 1714 1814 15 115 215 315 415 515 615 715 815 915 1015 1115 1215 1315 1415 1515 1615 1715 1815 16 116 216 316 416 516 1434 424 1534 524 1634 624 1734 724 1834 824 35 924 135 1024 235 1124 335 1224 435 1324 535 1424 635 1524 735 1624 835 1724 935 1824 1035 25 1135 125 1235 225 1335 325 1435 425 1535 525 1635 625 1735 725 1835 825 36 925 136 1025 236 1125 336 1225 436 1325 536 1425 636 1525 736 1625 836 1725 936 1825 1036 26 1136 126 1236 226 1336 326 1436 426 1536 526 1636 626 1736 726 1836 826 37 926 137 1026 237 1126 337 1226 437 1326 537 1426 637 1526 227 15 9 142 130 128 35 231 136 6 115 137 230 105 119 117 106 13 27 5 207 6 111 4 132 206 218 205 219 10 103 40 208 5 31 12 7 1 4 116 5 104 114 223 118 3 6 133 138 8 7 3 107 5 207 7 8 9 108 11 208 13 9 15 109 1 209 101 10 102 110 3 210 104 11 5 111 105 211 6 12 106 112 107 212 8 13 9 113 109 213 10 14 110 114 12 214 13 15 14 115 16 215 17 16 19 116 20 216 21 17 22 117 23 217 24 18 26 118 27 218 28 19 29 119 31 219 32 20 33 120 35 220 36 21 Copies Submitted Original value: 1 37 121 39 221 40 22 41 122 2 222 4 23 5 123 6 121 905 221 1005 22 1105 122 1205 23 1305 123 1405 223 1505 24 1605 124 6 224 106 25 206 125 306 225 406 TOTAL 26 506 126 606 226 706 27 806 227 906

 

Remaining amortization period is 44 years.

 

28 1006 128 1106 228 1206 29 1306 129 1406 229 1506 30 1606 130 7 230 207 31 307 131 407 231 507 132 607 232 707 33 807 133 907 233 1007 34 1107 134 1207 234 1407 35 1507 135 107 235 8 36 208 136 308 236 408 37 508 137 708 237 808 38 908 138 1008 238 1108 1229 1017 1329 1217 1429 1317 1529 1417 30 1517 130 717 230 1117 330 1617 430 18 530 118 630 157886357 218 730 318 830 152876832 418 930 518 1030 618 1130 718 1230 818 1330 918 1430 1018 1530 1118 31 1218 131 1318 231 1418 331 1518 431 1618 531 19 631 119 731 219 831 319 931 419 1031 519 1131 619 1231 719 1331 819 1531 919 32 1019 132 1219 232 1319 332 1419 432 1519 532 1619 632 20 732 120 832 220 932 320 1032 420 1132 520 1232 620 1332 720 1432 820 206 616 306 716 406 816 506 916 606 1016 706 1116 806 1216 906 1316 1006 1416 1106 1516 1206 1616 1306 1716 1406 1816 1506 17 1606 117 1706 217 1806 317 1906 417 7 517 107 617 207 717 307 817 407 917 507 1017 607 1117 707 1217 807 1317 907 1417 1007 1517 1107 1617 1207 1717 1307 1817 1407 18 1507 118 1607 218 1707 318 1807 418 1907 518 8 618 108 718 208 818 308 918 408 1018 508 1118 608 1218 708 1318 808 1418 908 1518 1008 1618 1108 1718 737 1626 837 1726 937 1826 1037 27 1137 127 1237 227 1337 327 1437 427 1537 527 1637 627 1737 727 1837 827 38 927 138 1027 238 1127 338 1227 438 1327 538 1427 638 1527 738 1627 838 1727 938 1827 1038 28 1138 128 1238 228 1338 328 1438 428 1538 528 1638 628 1738 728 1838 828 39 928 139 1028 239 1128 339 1228 439 1328 539 1428 639 1528 739 1628 839 1728 939 1828 1039 29 1139 129 1239 229 1339 329 1439 429 1539 529 1639 629 1739 729 1839 829 112 8 131 10 16 11 135 13 303 1 41 2 3 3 28 5 226 7 19 9 220 10 216 11 221 13 21 15 42 1 8 101 134 102 114 3 204 103 214 104 38 5 25 105 122 106 1 7 3 107 110 108 19 9 203 109 1 10 8 110 9 11 34 111 39 12 7 112 3 13 16 113 102 14 113 114 23 15 209 115 111 16 208 116 103 17 9 117 302 118 121 18 115 119 24 19 3 20 101 120 39 920 139 1020 239 1120 40 1220 140 1320 240 1420 41 1520 141 1620 241 21 42 121 142 221 242 321 43 421 143 521 243 621 44 821 144 921 244 1021 45 1121 C007565 245 1221 146 1321 246 1421 47 1521 247 1621 148 22 49 122 149 222 249 322 50 422 150 522 1 622 2 722 O 3 822 4 922 6 1022 7 1122 9 1222 10 1322 11 1422 12 1522 False Original value: N 14 23 15 123 16 223 17 323 19 423 20 523 21 623 23 723 24 823 25 923 223 24 124 224 25 125 225 26 126 226 27 127 227 28 128 228 29 129 229 30 130 230 31 131 231 32 132 232 33 133 233 34 134 234 1 101 201 301 401 501 2 102 202 302 402 502 3 103 203 303 1532 1208 33 1308 133 1408 233 1508 433 1608 533 608 633 9 733 109 833 209 933 309 1033 409 1133 509 1333 609 1433 709 1533 809 333 909 34 1009 134 1109 234 1209 434 1309 634 1409 734 1509 834 1609 934 10 1034 110 1134 210 1334 310 1434 410 1534 510 35 610 135 710 435 810 635 910 735 1010 835 1110 1035 1210 1135 1310 1335 1410 1435 1510 1535 1610 1 11 3 111 4 211 6 311 8 411 9 511 10 611 11 711 1 811 101 911 1208 1308 1408 1508 1608 1708 1808 1908 9 109 209 309 409 509 609 709 809 909 1009 1109 1209 1309 1409 1509 1609 1709 1809 1909 10 110 210 310 410 510 610 710 810 910 1010 1110 1210 1310 1410 1510 1610 1710 1810 1910 11 111 1818 929 19 1029 119 1129 219 1229 319 1329 419 1429 519 1529 619 1629 719 1729 819 1829 919 30 1019 130 1119 230 1219 330 1319 430 1419 530 1519 630 1619 730 1719 830 1819 930 20 1030 120 1130 220 1230 320 1330 420 1430 520 1530 620 1630 720 1730 820 1830 920 31 1020 131 1120 231 1220 331 1320 431 1420 531 1520 631 1620 731 1720 831 1820 931 21 1031 121 1131 221 1231 321 1331 421 1431 521 1531 621 1631 721 1731 821 1831 921 32 1021 132 40 120 140 106 240 117 340 7 440 202 540 11 640 16 740 26 840 17 940 127 1040 125 1140 6 1240 211 1340 7 1440 17 1540 36 1640 201 1740 1 1840 2 2 7 102 210 3 2 103 139 4 2 104 113 5 102 105 14 6 210 106 202 7 29 107 109 8 304 108 212 9 225 109 20 10 110 110 3 11 5 111 214 12 213 112 141 13 107 113 108 14 209 114 224 15 216 115 2 16 5 17 124 18 215 Other (Specify) 403 27 21 503 28 22 4 30 23 104 1 24 204 3 25 304 5 27 404 7 28 504 8 29 5 10 30 105 12 32 205 13 1 305 15 101 405 17 2 505 18 102 6 20 3 106 21 103 206 23 4 306 24 5 406 26 6 7 27 8 107 29 108 207 32 9 307 34 109 407 1 10 8 101 11 108 201 12 208 301 113 308 401 114 408 501 14 9 601 115 109 701 116 209 801 18 309 901 118 409 1001 19 10 1101 119 110 1201 22 210 1301 1 23 310 1401 3 24 410 1501 2 26 11 1601 5 28 111 2 7 29 211 102 9 30 311 202 11 31 411 302 13 32 12 402 15 33 112 502 16 35 212 602 18 36 312 702 23 38 412 802 1 39 13 902 4 40 201 1011 1023 301 1111 1123 401 1211 1223 501 1311 1323 601 1411 1423 701 1511 1523 801 1611 24 901 12 124 1001 112 224 1101 212 324 1201 312 424 1301 412 524 1401 512 624 1501 712 724 1601 812 824 1701 912 924 1801 1012 1024 1901 1112 1124 2 1212 1224 102 1312 1324 202 1412 1524 302 1512 1424 402 1612 25 502 13 125 602 113 225 702 213 325 802 313 425 902 413 525 1002 513 625 1102 613 725 1202 713 825 1302 813 925 1402 913 1025 1502 1013 1125 1602 1113 1225 1702 1213 1325 1802 False Original value: 2 1313 1425 1902 1413 1525 3 1513 1625 103 1613 26 203 14 126 303 114 226 403 214 326 503 314 426 603 414 526 703 514 626 803 614 726 903 714 826 1003 814 926 1103 914 1026 211 311 411 511 611 711 811 911 1011 1111 1211 1311 1411 1511 1611 1711 1811 1911 12 112 212 312 412 512 612 712 812 912 1012 1112 1212 1312 1412 1512 1612 1712 1812 13 113 213 313 413 513 613 713 813 913 1013 1113 1213 1121 232 1221 332 1321 432 1421 532 1521 632 1621 732 1721 832 1821 932 22 1032 122 1132 222 1232 322 1332 422 1432 522 1532 622 1632 722 1732 822 1832 922 33 1022 133 1122 233 1222 333 1322 433 1422 533 1522 633 1622 733 1722 833 1822 933 23 1033 123 1133 223 1233 323 1333 423 1433 523 1533 623 1633 723 1733 823 1833 923 34 1023 134 1123 234 1223 334 1323 434 1423 534 1523 634 1623 734 1723 834 1823 934 24 1034 124 1134 224 1234 324 1334 19 21 22 23 24 25 26 27 28 29 30 31 2 4 6 8 78 79 80 81 82 83 84 85 86 32 37 4 13 5 33 14 126 15 6 229 2 129 228 11 108 17 207 6 6 109 120 119 211 218 113 204 5 213 6 203 313 123 7 413 8 217 14 222 10 114 4 11 214 18 12 314 13 10 414 4 14 15 18 220 115 13 19 215 18 20 Purchases/Transfers: 315 12 21 Purchases/Transfers: 415 24 118 16 107 25 116 26 15 216 140 27 316 215 28 416 213 31 6 32 205 7 219 33 8 34 10 12 206 35 112 4 37 212 112 38 312 39 12 13 22 40 113 41 8 213 212 42 14 6 43 114 30 44 214 46 104 15 105 47 115 48 217 215 116 49 116 20 50 216 51 17 52 117 5 217 18 18 33 118 53 218 54 19 55 119 65 219 67 20 68 120 69 220 77 21 1
C007565 4-16 2018-01-01 2018-12-31 C007565 15-21 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-25 2018-12-31 C007565 0-19 2017-12-31 C007565 5-1 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-37 2018-12-31 C007565 1-16 2018-12-31 C007565 0-33 2017-12-31 C007565 2-24 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-28 2018-01-01 2018-12-31 C007565 15-22 2018-01-01 2018-12-31 C007565 15-34 2018-01-01 2018-12-31 C007565 10-23 2018-01-01 2018-12-31 C007565 1-5 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 10-33 2018-01-01 2018-12-31 C007565 14-22 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 3-3 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-18 2018-12-31 C007565 0-22 2017-12-31 C007565 18-24 2018-12-31 C007565 5-21 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 4-16 2018-01-01 2018-12-31 C007565 3-34 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 1-2 2018-01-01 2018-12-31 C007565 19-5 2018-12-31 C007565 0-25 2018-01-01 2018-12-31 C007565 19-11 2018-12-31 C007565 5-11 2018-01-01 2018-12-31 C007565 13-29 2018-01-01 2018-12-31 C007565 11-20 2018-01-01 2018-12-31 C007565 17-18 2018-12-31 C007565 3-40 2018-01-01 2018-12-31 C007565 7-21 2018-01-01 2018-12-31 C007565 10-8 2018-01-01 2018-12-31 C007565 12-13 2018-01-01 2018-12-31 C007565 11-28 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 0-10 2018-12-31 C007565 ferc:DirectPayrollDistributionMember 0-85 2018-01-01 2018-12-31 C007565 1-19 2018-12-31 C007565 10-19 2018-01-01 2018-12-31 C007565 5-14 2018-01-01 2018-12-31 C007565 3-39 2018-12-31 C007565 5-15 2018-12-31 C007565 0-45 2018-01-01 2018-12-31 C007565 17-15 2018-01-01 2018-12-31 C007565 1-14 2018-12-31 C007565 1-2 2018-01-01 2018-12-31 C007565 9-33 2018-01-01 2018-12-31 C007565 16-17 2018-01-01 2018-12-31 C007565 4-3 2018-01-01 2018-12-31 C007565 11-17 2018-01-01 2018-12-31 C007565 1-7 2017-12-31 C007565 8-6 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-3 2018-01-01 2018-12-31 C007565 8-25 2018-12-31 C007565 14-19 2018-01-01 2018-12-31 C007565 18-11 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 14-9 2018-01-01 2018-12-31 C007565 5-31 2018-01-01 2018-12-31 C007565 2-8 2018-01-01 2018-12-31 C007565 5-18 2018-01-01 2018-12-31 C007565 0-32 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-3 2018-01-01 2018-12-31 C007565 0-41 2018-01-01 2018-12-31 C007565 13-26 2018-01-01 2018-12-31 C007565 3-27 2018-01-01 2018-12-31 C007565 15-18 2018-12-31 C007565 4-31 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-14 2018-12-31 C007565 14-32 2018-12-31 C007565 5-27 2018-01-01 2018-12-31 C007565 12-16 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 1-31 2018-01-01 2018-12-31 C007565 ScheduleCommonUtilityPlantAndExpensesAbstract 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 0-79 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-4 2018-01-01 2018-12-31 C007565 13-18 2018-01-01 2018-12-31 C007565 1-28 2018-01-01 2018-12-31 C007565 1-28 2018-12-31 C007565 9-40 2018-01-01 2018-12-31 C007565 18-12 2018-01-01 2018-12-31 C007565 14-31 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:AfterThreeYearsMember 2017-12-31 C007565 7-11 2018-12-31 C007565 0-27 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-24 2018-01-01 2018-12-31 C007565 ferc:NitrogenOxideMember 2018-12-31 C007565 0-1 2018-12-31 C007565 2 2018-01-01 2018-12-31 C007565 3-3 2018-01-01 2018-12-31 C007565 4-10 2018-01-01 2018-12-31 C007565 12-12 2018-01-01 2018-12-31 C007565 17-11 2018-12-31 C007565 ferc:LandAndRightsMember 0-6 2018-01-01 2018-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 1-5 2018-12-31 C007565 6-36 2018-01-01 2018-12-31 C007565 0-22 2018-01-01 2018-12-31 C007565 11-31 2018-12-31 C007565 3-9 2018-01-01 2018-12-31 C007565 18-30 2018-01-01 2018-12-31 C007565 10-21 2018-01-01 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 2-18 2018-01-01 2018-12-31 C007565 5-28 2018-01-01 2018-12-31 C007565 5-7 2018-12-31 C007565 1-2 2018-01-01 2018-12-31 C007565 1-15 2018-01-01 2018-12-31 C007565 0-20 2018-01-01 2018-12-31 C007565 2-5 2018-01-01 2018-12-31 C007565 2-8 2018-01-01 2018-12-31 C007565 0-10 2018-12-31 C007565 14-2 2018-12-31 C007565 0-42 2018-01-01 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 10-10 2018-01-01 2018-12-31 C007565 15-23 2018-12-31 C007565 19-2 2018-01-01 2018-12-31 C007565 13-2 2018-01-01 2018-12-31 C007565 15-2 2018-01-01 2018-12-31 C007565 14-17 2018-12-31 C007565 0-32 2018-12-31 C007565 1-17 2018-12-31 C007565 11-11 2018-01-01 2018-12-31 C007565 0-6 2018-12-31 C007565 4-15 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-10 2018-01-01 2018-12-31 C007565 2-22 2018-01-01 2018-12-31 C007565 12-29 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-15 2018-01-01 2018-12-31 C007565 4-32 2018-01-01 2018-12-31 C007565 7-6 2018-01-01 2018-12-31 C007565 13-10 2018-12-31 C007565 17-40 2018-12-31 C007565 ferc:ElectricUtilityMember 2-1 2018-12-31 C007565 ferc:ElectricUtilityMember 1-23 2018-12-31 C007565 0-16 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 ferc:NonUtilityMember 0-6 2017-12-31 C007565 12-2 2018-12-31 C007565 12-28 2018-01-01 2018-12-31 C007565 17-16 2018-01-01 2018-12-31 C007565 16-4 2018-01-01 2018-12-31 C007565 4-15 2018-01-01 2018-12-31 C007565 9-12 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-8 2017-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 4-8 2018-12-31 C007565 13-32 2018-01-01 2018-12-31 C007565 17-32 2018-01-01 2018-12-31 C007565 6-35 2018-01-01 2018-12-31 C007565 11-30 2018-12-31 C007565 8-34 2018-12-31 C007565 2-17 2018-01-01 2018-12-31 C007565 14-27 2018-12-31 C007565 ferc:ElectricUtilityMember 0-15 2018-12-31 C007565 ferc:ElectricUtilityMember 2-8 2018-12-31 C007565 1-19 2018-01-01 2018-12-31 C007565 2-15 2018-01-01 2018-12-31 C007565 14-4 2018-01-01 2018-12-31 C007565 15-27 2018-01-01 2018-12-31 C007565 11-25 2018-12-31 C007565 9-18 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-6 2018-01-01 2018-12-31 C007565 ScheduleElectricPropertyLeasedToOthersAbstract 2018-01-01 2018-12-31 C007565 1-31 2018-01-01 2018-12-31 C007565 2-13 2018-01-01 2018-12-31 C007565 14-7 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 9-36 2018-12-31 C007565 11-2 2018-01-01 2018-12-31 C007565 18-20 2018-01-01 2018-12-31 C007565 12-4 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-32 2018-01-01 2018-12-31 C007565 15-11 2018-01-01 2018-12-31 C007565 1-19 2018-01-01 2018-12-31 C007565 9-17 2018-01-01 2018-12-31 C007565 1-15 2018-01-01 2018-12-31 C007565 5-19 2018-01-01 2018-12-31 C007565 1-9 2018-12-31 C007565 2-34 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 2-15 2018-01-01 2018-12-31 C007565 0-18 2018-01-01 2018-12-31 C007565 0-5 2017-01-01 2017-12-31 C007565 8-11 2018-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-38 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-30 2018-01-01 2018-12-31 C007565 3-11 2018-01-01 2018-12-31 C007565 12-40 2018-01-01 2018-12-31 C007565 0-18 2018-01-01 2018-12-31 C007565 2-21 2018-01-01 2018-12-31 C007565 7-31 2018-01-01 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 2-8 2018-01-01 2018-12-31 C007565 5-6 2018-01-01 2018-12-31 C007565 17-40 2018-01-01 2018-12-31 C007565 16-39 2018-12-31 C007565 17-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-13 2018-12-31 C007565 16-9 2018-01-01 2018-12-31 C007565 18-15 2018-01-01 2018-12-31 C007565 0-52 2018-01-01 2018-12-31 C007565 2-6 2018-01-01 2018-12-31 C007565 9-16 2018-12-31 C007565 10-34 2018-01-01 2018-12-31 C007565 1-34 2018-01-01 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 1-3 2018-01-01 2018-12-31 C007565 14-33 2018-12-31 C007565 12-29 2018-01-01 2018-12-31 C007565 12-19 2018-12-31 C007565 10-31 2018-01-01 2018-12-31 C007565 12-32 2018-01-01 2018-12-31 C007565 12-39 2018-01-01 2018-12-31 C007565 5-2 2018-01-01 2018-12-31 C007565 Oil-0 Oklaunion-0 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 6-36 2018-12-31 C007565 10-35 2018-01-01 2018-12-31 C007565 15-24 2018-01-01 2018-12-31 C007565 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2018-12-31 C007565 14-29 2018-01-01 2018-12-31 C007565 17-36 2018-01-01 2018-12-31 C007565 6-19 2018-01-01 2018-12-31 C007565 14-5 2018-12-31 C007565 10-5 2018-12-31 C007565 1-36 2018-01-01 2018-12-31 C007565 2-40 2018-12-31 C007565 5-3 2018-12-31 C007565 4-27 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 3-9 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-21 2018-12-31 C007565 2-16 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 1-20 2018-12-31 C007565 10-23 2018-01-01 2018-12-31 C007565 1-40 2018-12-31 C007565 11-26 2018-01-01 2018-12-31 C007565 5-14 2018-01-01 2018-12-31 C007565 8-29 2018-01-01 2018-12-31 C007565 2-6 2018-12-31 C007565 ferc:OtherUtilityMember 0-17 2018-01-01 2018-12-31 C007565 18-33 2018-12-31 C007565 2-23 2018-12-31 C007565 ferc:ElectricUtilityMember 0-39 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-13 2018-12-31 C007565 15-33 2018-01-01 2018-12-31 C007565 9-21 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-14 2018-01-01 2018-12-31 C007565 1-10 2018-01-01 2018-12-31 C007565 5-23 2018-12-31 C007565 0-14 2017-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 13-14 2018-01-01 2018-12-31 C007565 16-14 2018-01-01 2018-12-31 C007565 8-3 2018-01-01 2018-12-31 C007565 6-40 2018-01-01 2018-12-31 C007565 6-12 2018-12-31 C007565 11-23 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 0-48 2018-01-01 2018-12-31 C007565 6-40 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 11-28 2018-01-01 2018-12-31 C007565 17-6 2018-01-01 2018-12-31 C007565 15-13 2018-01-01 2018-12-31 C007565 18-10 2018-01-01 2018-12-31 C007565 0-85 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 16-23 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-21 2018-01-01 2018-12-31 C007565 14-14 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-3 2018-01-01 2018-12-31 C007565 0-29 2018-01-01 2018-12-31 C007565 1-15 2018-01-01 2018-12-31 C007565 1-11 2018-12-31 C007565 1-15 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-7 2017-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 0-15 2018-12-31 C007565 4-20 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-11 2018-12-31 C007565 4-7 2018-12-31 C007565 19-8 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-2 2018-01-01 2018-12-31 C007565 11-37 2018-01-01 2018-12-31 C007565 6-28 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-9 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 4-1 2018-01-01 2018-12-31 C007565 1-13 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2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 0-4 2017-12-31 C007565 14-7 2018-12-31 C007565 1-6 2018-01-01 2018-12-31 C007565 1-42 2018-01-01 2018-12-31 C007565 0-21 2018-01-01 2018-12-31 C007565 17-6 2018-12-31 C007565 1-2 2018-01-01 2018-12-31 C007565 1-16 2018-01-01 2018-12-31 C007565 1-17 2018-12-31 C007565 ferc:ElectricUtilityMember 1-40 2018-12-31 C007565 10-24 2018-01-01 2018-12-31 C007565 1-19 2018-01-01 2018-12-31 C007565 9-1 2018-01-01 2018-12-31 C007565 16-19 2018-12-31 C007565 3-15 2018-01-01 2018-12-31 C007565 18-29 2018-12-31 C007565 7-15 2018-01-01 2018-12-31 C007565 0-20 2018-12-31 C007565 2-18 2018-01-01 2018-12-31 C007565 1-36 2018-01-01 2018-12-31 C007565 8-30 2018-01-01 2018-12-31 C007565 4-39 2018-01-01 2018-12-31 C007565 7-37 2018-12-31 C007565 ferc:ElectricUtilityMember 0-9 2018-01-01 2018-12-31 C007565 17-14 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 0-67 2018-01-01 2018-12-31 C007565 1-8 2018-01-01 2018-12-31 C007565 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2018-12-31 C007565 4-5 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 4-12 2018-01-01 2018-12-31 C007565 1-15 2018-12-31 C007565 1-9 2018-01-01 2018-12-31 C007565 0-13 2018-12-31 C007565 0-28 2018-01-01 2018-12-31 C007565 11-31 2018-01-01 2018-12-31 C007565 1-35 2018-12-31 C007565 12-1 2018-12-31 C007565 0-19 2018-12-31 C007565 13-28 2018-12-31 C007565 ferc:ElectricUtilityMember 1-6 2018-01-01 2018-12-31 C007565 11-6 2018-01-01 2018-12-31 C007565 12-18 2018-01-01 2018-12-31 C007565 15-15 2018-01-01 2018-12-31 C007565 1-37 2018-12-31 C007565 5-15 2018-01-01 2018-12-31 C007565 8-19 2018-12-31 C007565 2-46 2018-01-01 2018-12-31 C007565 9-27 2018-12-31 C007565 3-16 2018-12-31 C007565 2-5 2018-01-01 2018-12-31 C007565 9-37 2018-12-31 C007565 17-22 2018-12-31 C007565 10-27 2018-12-31 C007565 1-10 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-24 2018-01-01 2018-12-31 C007565 15-29 2018-01-01 2018-12-31 C007565 9-9 2018-01-01 2018-12-31 C007565 13-38 2018-12-31 C007565 1-10 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-25 2018-12-31 C007565 6-21 2018-01-01 2018-12-31 C007565 2-30 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-4 2017-12-31 C007565 5 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-2 2018-12-31 C007565 3-15 2018-01-01 2018-12-31 C007565 5-31 2018-01-01 2018-12-31 C007565 12-11 2018-12-31 C007565 1-32 2018-01-01 2018-12-31 C007565 0-7 2017-12-31 C007565 3-2 2018-01-01 2018-12-31 C007565 5-28 2018-01-01 2018-12-31 C007565 15-10 2018-01-01 2018-12-31 C007565 4-2 2018-01-01 2018-12-31 C007565 12-18 2018-01-01 2018-12-31 C007565 14-36 2018-12-31 C007565 ferc:ElectricUtilityMember 0-10 2018-01-01 2018-12-31 C007565 14-12 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 11-29 2018-01-01 2018-12-31 C007565 16-34 2018-12-31 C007565 2-16 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 2-11 2018-01-01 2018-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 11-24 2018-12-31 C007565 8-21 2018-01-01 2018-12-31 C007565 2-30 2018-01-01 2018-12-31 C007565 1-34 2018-12-31 C007565 4-13 2018-12-31 C007565 10-4 2018-01-01 2018-12-31 C007565 0-13 2018-12-31 C007565 12-4 2018-01-01 2018-12-31 C007565 15-16 2018-12-31 C007565 16-15 2018-01-01 2018-12-31 C007565 1-6 2018-12-31 C007565 0-21 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-39 2018-01-01 2018-12-31 C007565 16-10 2018-01-01 2018-12-31 C007565 15-20 2018-12-31 C007565 1-1 2018-01-01 2018-12-31 C007565 14-21 2018-01-01 2018-12-31 C007565 6-6 2018-12-31 C007565 2-7 2018-01-01 2018-12-31 C007565 14-27 2018-01-01 2018-12-31 C007565 4-26 2018-01-01 2018-12-31 C007565 6-17 2018-12-31 C007565 2-36 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-2 2018-01-01 2018-12-31 C007565 7-25 2018-01-01 2018-12-31 C007565 7-8 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-27 2018-12-31 C007565 1-18 2018-01-01 2018-12-31 C007565 1-35 2018-01-01 2018-12-31 C007565 0-18 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 7-3 2018-01-01 2018-12-31 C007565 19-7 2018-12-31 C007565 17-10 2018-01-01 2018-12-31 C007565 0-11 2018-01-01 2018-12-31 C007565 1-40 2018-01-01 2018-12-31 C007565 2-15 2018-12-31 C007565 5-33 2018-01-01 2018-12-31 C007565 2-33 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 12-23 2018-01-01 2018-12-31 C007565 13-25 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-12 2018-12-31 C007565 1-21 2018-12-31 C007565 3-20 2018-01-01 2018-12-31 C007565 10-32 2018-12-31 C007565 0-7 2018-12-31 C007565 18-1 2018-01-01 2018-12-31 C007565 6-3 2018-01-01 2018-12-31 C007565 18-22 2018-12-31 C007565 12-16 2018-12-31 C007565 12-11 2018-01-01 2018-12-31 C007565 6-6 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-5 2018-12-31 C007565 ferc:ElectricUtilityMember 2-12 2018-01-01 2018-12-31 C007565 19-4 2018-12-31 C007565 Coal-0 Oklaunion-0 2018-01-01 2018-12-31 C007565 3-24 2018-01-01 2018-12-31 C007565 3-29 2018-01-01 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 18-28 2018-12-31 C007565 ferc:SulfurDioxideMember 2018-12-31 C007565 0-19 2018-01-01 2018-12-31 C007565 1-25 2018-01-01 2018-12-31 C007565 10-16 2018-12-31 C007565 10-40 2018-01-01 2018-12-31 C007565 17-12 2018-12-31 C007565 2-37 2018-12-31 C007565 7-23 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 6-26 2018-12-31 C007565 4-1 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 8-18 2018-12-31 C007565 0-27 2018-01-01 2018-12-31 C007565 1-7 2018-01-01 2018-12-31 C007565 0-22 2018-01-01 2018-12-31 C007565 17-13 2018-01-01 2018-12-31 C007565 15-31 2018-12-31 C007565 6-20 2018-01-01 2018-12-31 C007565 4-8 2018-01-01 2018-12-31 C007565 7-16 2018-01-01 2018-12-31 C007565 0-21 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-19 2018-01-01 2018-12-31 C007565 15-21 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 10-15 2018-01-01 2018-12-31 C007565 5-25 2018-12-31 C007565 14-19 2018-01-01 2018-12-31 C007565 16-10 2018-01-01 2018-12-31 C007565 3-22 2018-12-31 C007565 ferc:ElectricUtilityMember 0-18 2018-12-31 C007565 0-49 2018-01-01 2018-12-31 C007565 ferc:OtherUtilityMember 2017-12-31 C007565 4-2 2018-12-31 C007565 ferc:ElectricUtilityMember 0-32 2018-01-01 2018-12-31 C007565 0-32 2018-01-01 2018-12-31 C007565 0-26 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-11 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-31 2018-01-01 2018-12-31 C007565 14-24 2018-01-01 2018-12-31 C007565 11-13 2018-12-31 C007565 15-7 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 12-14 2018-01-01 2018-12-31 C007565 0-29 2017-12-31 C007565 14-28 2018-01-01 2018-12-31 C007565 18-32 2018-01-01 2018-12-31 C007565 4-37 2018-01-01 2018-12-31 C007565 0-31 2018-01-01 2018-12-31 C007565 15-34 2018-01-01 2018-12-31 C007565 4-26 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 11-10 2018-12-31 C007565 ferc:ElectricUtilityMember 2-28 2018-01-01 2018-12-31 C007565 4-10 2018-01-01 2018-12-31 C007565 7-22 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-11 2018-01-01 2018-12-31 C007565 0-39 2018-01-01 2018-12-31 C007565 7-4 2018-01-01 2018-12-31 C007565 ferc:AugustMember 0 2018-01-01 2018-12-31 C007565 12-31 2018-12-31 C007565 12-7 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-2 2018-12-31 C007565 2-3 2018-01-01 2018-12-31 C007565 12-21 2018-01-01 2018-12-31 C007565 0-22 2018-12-31 C007565 4-21 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-18 2018-01-01 2018-12-31 C007565 15-23 2018-01-01 2018-12-31 C007565 1-6 2018-01-01 2018-12-31 C007565 0-19 2018-01-01 2018-12-31 C007565 7-35 2018-12-31 C007565 4-34 2018-01-01 2018-12-31 C007565 13-21 2018-12-31 C007565 ferc:ElectricUtilityMember 1-28 2018-12-31 C007565 2-16 2018-01-01 2018-12-31 C007565 15-35 2018-01-01 2018-12-31 C007565 9-34 2018-01-01 2018-12-31 C007565 13-30 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 16-5 2018-01-01 2018-12-31 C007565 2-10 2018-01-01 2018-12-31 C007565 15-25 2018-01-01 2018-12-31 C007565 16-16 2018-01-01 2018-12-31 C007565 9-39 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-30 2018-01-01 2018-12-31 C007565 16-9 2018-12-31 C007565 0-40 2018-01-01 2018-12-31 C007565 14-3 2018-01-01 2018-12-31 C007565 9-14 2018-12-31 C007565 0-20 2018-01-01 2018-12-31 C007565 8-22 2018-12-31 C007565 12-17 2018-01-01 2018-12-31 C007565 1-18 2018-01-01 2018-12-31 C007565 0-24 2017-12-31 C007565 0-14 2018-12-31 C007565 5-16 2018-01-01 2018-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 ferc:OtherUtilityMember 0-17 2017-12-31 C007565 1-19 2018-01-01 2018-12-31 C007565 0-24 2018-12-31 C007565 8-36 2018-12-31 C007565 6-16 2018-01-01 2018-12-31 C007565 2018-12-31 C007565 15-35 2018-01-01 2018-12-31 C007565 15-16 2018-01-01 2018-12-31 C007565 7-17 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 1-22 2018-01-01 2018-12-31 C007565 12-27 2018-12-31 C007565 ferc:ElectricUtilityMember 0-12 2018-01-01 2018-12-31 C007565 0-1 2018-12-31 C007565 ferc:ElectricUtilityMember 1-20 2018-01-01 2018-12-31 C007565 3-4 2018-01-01 2018-12-31 C007565 1-8 2018-01-01 2018-12-31 C007565 0-5 2018-12-31 C007565 0-39 2018-01-01 2018-12-31 C007565 2-10 2018-01-01 2018-12-31 C007565 ferc:ElectricPlantInServiceMember ferc:ElectricUtilityMember 2017-12-31 C007565 15-12 2018-01-01 2018-12-31 C007565 1-30 2018-01-01 2018-12-31 C007565 1-32 2018-01-01 2018-12-31 C007565 8-14 2018-12-31 C007565 1-5 2018-01-01 2018-12-31 C007565 2-44 2018-01-01 2018-12-31 C007565 6-13 2018-01-01 2018-12-31 C007565 15-19 2018-01-01 2018-12-31 C007565 13-39 2018-12-31 C007565 1-3 2018-01-01 2018-12-31 C007565 13-23 2018-12-31 C007565 12-3 2018-12-31 C007565 14-9 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 4 2018-01-01 2018-12-31 C007565 ScheduleStatementOfIncomeAbstract 2018-01-01 2018-12-31 C007565 1-19 2018-01-01 2018-12-31 C007565 0-3 2018-12-31 C007565 18-31 2018-12-31 C007565 1-16 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-6 2018-01-01 2018-12-31 C007565 3-33 2018-01-01 2018-12-31 C007565 0-43 2018-01-01 2018-12-31 C007565 12-9 2018-01-01 2018-12-31 C007565 5-8 2018-12-31 C007565 6-25 2018-01-01 2018-12-31 C007565 17-11 2018-01-01 2018-12-31 C007565 12-34 2018-12-31 C007565 5-25 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 0-39 2018-01-01 2018-12-31 C007565 2-15 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 16-36 2018-12-31 C007565 1-3 2018-01-01 2018-12-31 C007565 11-33 2018-12-31 C007565 7-7 2018-01-01 2018-12-31 C007565 7-16 2018-12-31 C007565 14-20 2018-01-01 2018-12-31 C007565 11-37 2018-12-31 C007565 16-37 2018-12-31 C007565 ferc:ElectricUtilityMember 0-2 2018-12-31 C007565 15-37 2018-01-01 2018-12-31 C007565 3-3 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-5 2018-01-01 2018-12-31 C007565 3-25 2018-12-31 C007565 10-35 2018-12-31 C007565 16-21 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 10-4 2018-01-01 2018-12-31 C007565 5-25 2018-01-01 2018-12-31 C007565 1-1 2018-01-01 2018-12-31 C007565 17-20 2018-12-31 C007565 4-11 2018-12-31 C007565 4-12 2018-01-01 2018-12-31 C007565 1-41 2018-01-01 2018-12-31 C007565 0-33 2018-12-31 C007565 7-13 2018-01-01 2018-12-31 C007565 8-27 2018-12-31 C007565 ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract 2018-01-01 2018-12-31 C007565 2-22 2018-01-01 2018-12-31 C007565 2-29 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 9-19 2018-01-01 2018-12-31 C007565 18-5 2018-12-31 C007565 9-27 2018-01-01 2018-12-31 C007565 8-38 2018-12-31 C007565 4-17 2018-12-31 C007565 17-25 2018-01-01 2018-12-31 C007565 15-3 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 12-31 2018-01-01 2018-12-31 C007565 18-8 2018-01-01 2018-12-31 C007565 9-28 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2018-12-31 C007565 5-37 2018-01-01 2018-12-31 C007565 3-11 2018-01-01 2018-12-31 C007565 1-17 2018-01-01 2018-12-31 C007565 2-32 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 7-13 2018-12-31 C007565 10-27 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 11-5 2018-01-01 2018-12-31 C007565 8-35 2018-12-31 C007565 ferc:ElectricUtilityMember 0-27 2018-12-31 C007565 ferc:ElectricUtilityMember 2-20 2018-01-01 2018-12-31 C007565 7-35 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 10-26 2018-01-01 2018-12-31 C007565 18-3 2018-01-01 2018-12-31 C007565 ferc:NitrogenOxideMember ferc:CurrentYearMember 2018-12-31 C007565 0-35 2018-01-01 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 11-36 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-9 2018-12-31 C007565 9-9 2018-01-01 2018-12-31 C007565 11-35 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:ThreeYearsMember 2018-12-31 C007565 0-4 2017-12-31 C007565 3-10 2018-12-31 C007565 2-21 2018-12-31 C007565 SchedulePumpedStorageGeneratingPlantStatisticsAbstract 2018-01-01 2018-12-31 C007565 1-11 2018-01-01 2018-12-31 C007565 3-36 2018-01-01 2018-12-31 C007565 17-12 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-14 2018-12-31 C007565 0-11 2018-01-01 2018-12-31 C007565 10-23 2018-12-31 C007565 1-39 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-40 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 10-26 2018-12-31 C007565 1-37 2018-01-01 2018-12-31 C007565 9-18 2018-12-31 C007565 3-27 2018-01-01 2018-12-31 C007565 9-25 2018-01-01 2018-12-31 C007565 4-24 2018-12-31 C007565 12-33 2018-01-01 2018-12-31 C007565 0-24 2017-12-31 C007565 7-9 2018-01-01 2018-12-31 C007565 8-12 2018-01-01 2018-12-31 C007565 5-31 2018-12-31 C007565 7-28 2018-12-31 C007565 1-21 2018-01-01 2018-12-31 C007565 7-38 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 0-18 2017-12-31 C007565 15-20 2018-01-01 2018-12-31 C007565 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C007565 11-34 2018-01-01 2018-12-31 C007565 0-68 2018-01-01 2018-12-31 C007565 16-31 2018-12-31 C007565 14-13 2018-01-01 2018-12-31 C007565 0-13 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 5-29 2018-01-01 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:NextTwelveMonthsMember 2017-12-31 C007565 ferc:ElectricUtilityMember 0-42 2018-01-01 2018-12-31 C007565 5-19 2018-01-01 2018-12-31 C007565 5-35 2018-01-01 2018-12-31 C007565 4-9 2018-12-31 C007565 ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract 2018-01-01 2018-12-31 C007565 0-43 2018-01-01 2018-12-31 C007565 10-31 2018-01-01 2018-12-31 C007565 1-8 2018-01-01 2018-12-31 C007565 6-7 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-13 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-21 2018-12-31 C007565 12-1 2018-01-01 2018-12-31 C007565 1-41 2018-01-01 2018-12-31 C007565 5-12 2018-12-31 C007565 ferc:OtherElectricUtilityMember 2018-12-31 C007565 3-16 2018-01-01 2018-12-31 C007565 5-5 2018-01-01 2018-12-31 C007565 12-33 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 11-32 2018-01-01 2018-12-31 C007565 19-5 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 5-12 2018-01-01 2018-12-31 C007565 9-11 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 10-3 2018-12-31 C007565 1-27 2018-01-01 2018-12-31 C007565 15-29 2018-01-01 2018-12-31 C007565 15-17 2018-01-01 2018-12-31 C007565 9-12 2018-01-01 2018-12-31 C007565 8-26 2018-01-01 2018-12-31 C007565 18-2 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 14-20 2018-12-31 C007565 11-21 2018-01-01 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-4 2018-12-31 C007565 17-21 2018-12-31 C007565 4-3 2018-12-31 C007565 6-3 2018-12-31 C007565 0-55 2017-01-01 2017-12-31 C007565 7-5 2018-01-01 2018-12-31 C007565 19-10 2018-12-31 C007565 13-19 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-7 2018-01-01 2018-12-31 C007565 6 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-23 2018-12-31 C007565 0-15 2018-12-31 C007565 2-17 2018-01-01 2018-12-31 C007565 8-29 2018-12-31 C007565 ferc:ElectricUtilityMember 1-40 2018-01-01 2018-12-31 C007565 0-41 2018-01-01 2018-12-31 C007565 1-13 2018-12-31 C007565 8-5 2018-01-01 2018-12-31 C007565 14-39 2018-12-31 C007565 ferc:ElectricUtilityMember 2-23 2018-01-01 2018-12-31 C007565 0-33 2018-01-01 2018-12-31 C007565 15-21 2018-01-01 2018-12-31 C007565 3-20 2018-12-31 C007565 16-3 2018-01-01 2018-12-31 C007565 4-18 2018-01-01 2018-12-31 C007565 ferc:MarchMember 0 2018-01-01 2018-12-31 C007565 18-26 2018-01-01 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 2-18 2018-12-31 C007565 0-33 2017-01-01 2017-12-31 C007565 9-3 2018-12-31 C007565 13-31 2018-12-31 C007565 1-28 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-19 2018-01-01 2018-12-31 C007565 7-10 2018-01-01 2018-12-31 C007565 9-32 2018-01-01 2018-12-31 C007565 3-6 2018-01-01 2018-12-31 C007565 5-2 2018-12-31 C007565 7-38 2018-12-31 C007565 0-65 2018-01-01 2018-12-31 C007565 13-10 2018-01-01 2018-12-31 C007565 5-39 2018-01-01 2018-12-31 C007565 13-17 2018-12-31 C007565 8-2 2018-01-01 2018-12-31 C007565 0-33 2018-12-31 C007565 5-8 2018-01-01 2018-12-31 C007565 SchedulePurchasedPowerAbstract 2018-01-01 2018-12-31 C007565 4-12 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-16 2018-01-01 2018-12-31 C007565 3-5 2018-01-01 2018-12-31 C007565 12-25 2018-12-31 C007565 8-31 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 6-14 2018-01-01 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 11-22 2018-01-01 2018-12-31 C007565 18-16 2018-12-31 C007565 7-27 2018-01-01 2018-12-31 C007565 0-18 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 11-21 2018-12-31 C007565 2-42 2018-01-01 2018-12-31 C007565 16-1 2018-01-01 2018-12-31 C007565 ferc:OtherUtilityMember 0-17 2018-12-31 C007565 2-15 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-17 2018-12-31 C007565 10-2 2018-01-01 2018-12-31 C007565 ferc:DirectPayrollDistributionMember 0-79 2018-01-01 2018-12-31 C007565 1-7 2018-01-01 2018-12-31 C007565 1-33 2018-01-01 2018-12-31 C007565 3-26 2018-01-01 2018-12-31 C007565 8-3 2018-01-01 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 6-11 2018-01-01 2018-12-31 C007565 0-25 2018-01-01 2018-12-31 C007565 4-2 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 3-2 2018-01-01 2018-12-31 C007565 ferc:SulfurDioxideMember 1 2018-01-01 2018-12-31 C007565 14-4 2018-01-01 2018-12-31 C007565 14-26 2018-01-01 2018-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 16-15 2018-01-01 2018-12-31 C007565 4-32 2018-01-01 2018-12-31 C007565 3-14 2018-12-31 C007565 ferc:ElectricUtilityMember 0-34 2018-12-31 C007565 1-16 2018-01-01 2018-12-31 C007565 7-29 2018-01-01 2018-12-31 C007565 8-22 2018-01-01 2018-12-31 C007565 0-25 2018-01-01 2018-12-31 C007565 5-23 2018-01-01 2018-12-31 C007565 8-17 2018-01-01 2018-12-31 C007565 8-31 2018-12-31 C007565 ferc:ElectricUtilityMember 1-6 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 9-32 2018-01-01 2018-12-31 C007565 0-28 2018-01-01 2018-12-31 C007565 5-5 2018-01-01 2018-12-31 C007565 ferc:MayMember 0 2018-01-01 2018-12-31 C007565 5-24 2018-12-31 C007565 2-24 2018-12-31 C007565 9-30 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-23 2018-01-01 2018-12-31 C007565 2-2 2018-01-01 2018-12-31 C007565 0-38 2018-01-01 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:TwoYearsMember 2018-12-31 C007565 0-4 2018-12-31 C007565 5-32 2018-12-31 C007565 ferc:ElectricUtilityMember 2-11 2018-01-01 2018-12-31 C007565 11-2 2018-12-31 C007565 1-12 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-1 2018-01-01 2018-12-31 C007565 2-20 2018-01-01 2018-12-31 C007565 ferc:DirectPayrollDistributionMember 0-84 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-12 2018-12-31 C007565 18-20 2018-12-31 C007565 1-11 2018-01-01 2018-12-31 C007565 17-29 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-4 2018-01-01 2018-12-31 C007565 7-11 2018-01-01 2018-12-31 C007565 5-30 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 15-6 2018-01-01 2018-12-31 C007565 10-28 2018-01-01 2018-12-31 C007565 5-30 2018-01-01 2018-12-31 C007565 1-31 2018-01-01 2018-12-31 C007565 2-11 2018-01-01 2018-12-31 C007565 12-6 2018-01-01 2018-12-31 C007565 1-7 2018-12-31 C007565 9-24 2018-12-31 C007565 ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-12 2018-01-01 2018-12-31 C007565 10-14 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-1 2018-12-31 C007565 16-32 2018-01-01 2018-12-31 C007565 4-28 2018-01-01 2018-12-31 C007565 0-29 2018-12-31 C007565 17-28 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 15-35 2018-12-31 C007565 2-17 2018-12-31 C007565 19-1 2018-12-31 C007565 0-41 2017-12-31 C007565 1-46 2018-01-01 2018-12-31 C007565 7-27 2018-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 1-30 2018-01-01 2018-12-31 C007565 0-15 2018-12-31 C007565 ferc:ElectricUtilityMember ferc:ElectricPlantInServiceMember 0-16 2018-01-01 2018-12-31 C007565 7-26 2018-01-01 2018-12-31 C007565 0-26 2017-12-31 C007565 6-8 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-39 2018-12-31 C007565 ferc:ElectricUtilityMember 0-37 2018-12-31 C007565 7-36 2018-12-31 C007565 1 2018-01-01 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 3-16 2018-01-01 2018-12-31 C007565 ferc:NitrogenOxideMember ferc:CurrentYearMember 2017-12-31 C007565 9-34 2018-01-01 2018-12-31 C007565 0-28 2018-12-31 C007565 ferc:ElectricUtilityMember 0-16 2018-01-01 2018-12-31 C007565 0-37 2018-12-31 C007565 ferc:OperatingUtilityMember 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-20 2018-01-01 2018-12-31 C007565 2-35 2018-01-01 2018-12-31 C007565 4-28 2018-01-01 2018-12-31 C007565 1-2 2017-12-31 C007565 13-27 2018-12-31 C007565 12-38 2018-12-31 C007565 0-6 2017-12-31 C007565 15-19 2018-01-01 2018-12-31 C007565 4-19 2018-12-31 C007565 2-29 2018-01-01 2018-12-31 C007565 16-5 2018-01-01 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 11-5 2018-12-31 C007565 3-8 2018-01-01 2018-12-31 C007565 16-35 2018-01-01 2018-12-31 C007565 3-10 2018-01-01 2018-12-31 C007565 1-19 2017-12-31 C007565 ferc:SteamProductionPlantMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C007565 19-9 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 0-20 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-33 2018-12-31 C007565 2-37 2018-01-01 2018-12-31 C007565 11-10 2018-01-01 2018-12-31 C007565 18-33 2018-01-01 2018-12-31 C007565 0-40 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-13 2018-01-01 2018-12-31 C007565 6-34 2018-01-01 2018-12-31 C007565 12-8 2018-01-01 2018-12-31 C007565 1-22 2018-12-31 C007565 2-3 2018-01-01 2018-12-31 C007565 2-18 2018-01-01 2018-12-31 C007565 0-4 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 2-3 2018-01-01 2018-12-31 C007565 3-6 2018-12-31 C007565 10-39 2018-01-01 2018-12-31 C007565 0-27 2018-01-01 2018-12-31 C007565 8-2 2018-12-31 C007565 1-16 2018-01-01 2018-12-31 C007565 0-22 2018-01-01 2018-12-31 C007565 3-14 2018-01-01 2018-12-31 C007565 15-11 2018-01-01 2018-12-31 C007565 4-4 2018-12-31 C007565 17-3 2018-01-01 2018-12-31 C007565 15-17 2018-01-01 2018-12-31 C007565 11-38 2018-01-01 2018-12-31 C007565 11-27 2018-01-01 2018-12-31 C007565 16-30 2018-12-31 C007565 5-6 2018-12-31 C007565 9-4 2018-01-01 2018-12-31 C007565 3-24 2018-12-31 C007565 13-21 2018-01-01 2018-12-31 C007565 16-30 2018-01-01 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 7-15 2018-12-31 C007565 12-12 2018-12-31 C007565 2-4 2018-01-01 2018-12-31 C007565 8-34 2018-01-01 2018-12-31 C007565 8-9 2018-12-31 C007565 8-32 2018-01-01 2018-12-31 C007565 3-2 2018-01-01 2018-12-31 C007565 1-37 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C007565 2-36 2018-01-01 2018-12-31 C007565 2-12 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-15 2018-12-31 C007565 0-38 2018-01-01 2018-12-31 C007565 8-40 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-4 2018-01-01 2018-12-31 C007565 8-6 2018-01-01 2018-12-31 C007565 7-1 2018-01-01 2018-12-31 C007565 0-44 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 6-5 2018-01-01 2018-12-31 C007565 1-20 2018-01-01 2018-12-31 C007565 10-22 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 11-29 2018-01-01 2018-12-31 C007565 8-1 2018-12-31 C007565 1-43 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-22 2018-01-01 2018-12-31 C007565 3-30 2018-01-01 2018-12-31 C007565 0-22 2018-01-01 2018-12-31 C007565 4-4 2018-01-01 2018-12-31 C007565 15-33 2018-12-31 C007565 4-34 2018-01-01 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 4-6 2018-01-01 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 11-40 2018-01-01 2018-12-31 C007565 0-69 2018-01-01 2018-12-31 C007565 7-12 2018-12-31 C007565 11-3 2018-01-01 2018-12-31 C007565 12-15 2018-01-01 2018-12-31 C007565 ferc:NonUtilityMember 0-6 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-19 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 9-35 2018-01-01 2018-12-31 C007565 10-38 2018-01-01 2018-12-31 C007565 8-33 2018-12-31 C007565 ScheduleNuclearFuelMaterialsAbstract 2018-01-01 2018-12-31 C007565 12-14 2018-01-01 2018-12-31 C007565 4-20 2018-12-31 C007565 2-19 2018-01-01 2018-12-31 C007565 15-15 2018-12-31 C007565 6 2018-01-01 2018-12-31 C007565 9-15 2018-01-01 2018-12-31 C007565 19-6 2018-12-31 C007565 16-38 2018-12-31 C007565 8-22 2018-01-01 2018-12-31 C007565 2-24 2018-01-01 2018-12-31 C007565 13-16 2018-12-31 C007565 16-39 2018-01-01 2018-12-31 C007565 3-20 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-4 2018-01-01 2018-12-31 C007565 8-30 2018-12-31 C007565 2-8 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 16-21 2018-01-01 2018-12-31 C007565 11-24 2018-01-01 2018-12-31 C007565 2-2 2018-01-01 2018-12-31 C007565 11-18 2018-12-31 C007565 ferc:ElectricUtilityMember 2-17 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 2-17 2018-01-01 2018-12-31 C007565 5-9 2018-12-31 C007565 3-10 2018-01-01 2018-12-31 C007565 1-22 2018-01-01 2018-12-31 C007565 11-15 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 2-27 2018-01-01 2018-12-31 C007565 10-34 2018-12-31 C007565 2-20 2018-01-01 2018-12-31 C007565 6-38 2018-01-01 2018-12-31 C007565 0-28 2018-01-01 2018-12-31 C007565 14-20 2018-01-01 2018-12-31 C007565 6-27 2018-01-01 2018-12-31 C007565 11-15 2018-12-31 C007565 8-6 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-19 2018-01-01 2018-12-31 C007565 5-20 2018-12-31 C007565 3-10 2018-01-01 2018-12-31 C007565 11-18 2018-01-01 2018-12-31 C007565 11-12 2018-12-31 C007565 13-16 2018-01-01 2018-12-31 C007565 0-51 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-9 2018-01-01 2018-12-31 C007565 18-18 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 2-18 2018-01-01 2018-12-31 C007565 2-7 2018-01-01 2018-12-31 C007565 9-28 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-22 2018-12-31 C007565 ferc:ElectricUtilityMember 0-13 2018-01-01 2018-12-31 C007565 0-18 2018-12-31 C007565 0-17 2018-01-01 2018-12-31 C007565 18-9 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 17-17 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-33 2018-12-31 C007565 0-18 2018-01-01 2018-12-31 C007565 14-9 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-41 2018-12-31 C007565 2-1 2018-01-01 2018-12-31 C007565 1-12 2018-01-01 2018-12-31 C007565 14-10 2018-01-01 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 14-24 2018-01-01 2018-12-31 C007565 2-19 2018-01-01 2018-12-31 C007565 8-2 2018-01-01 2018-12-31 C007565 12-25 2018-01-01 2018-12-31 C007565 0-1 2018-12-31 C007565 2-15 2018-01-01 2018-12-31 C007565 11-2 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-31 2018-01-01 2018-12-31 C007565 17-4 2018-01-01 2018-12-31 C007565 7-30 2018-01-01 2018-12-31 C007565 7-16 2018-01-01 2018-12-31 C007565 17-15 2018-12-31 C007565 13-20 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 7-4 2018-01-01 2018-12-31 C007565 12-6 2018-12-31 C007565 14-14 2018-01-01 2018-12-31 C007565 1-15 2018-01-01 2018-12-31 C007565 1-42 2018-01-01 2018-12-31 C007565 2-11 2018-01-01 2018-12-31 C007565 10-37 2018-01-01 2018-12-31 C007565 ferc:DistributionPlantMember ferc:ElectricUtilityMember 2018-01-01 2018-12-31 C007565 2-35 2018-01-01 2018-12-31 C007565 11-1 2018-01-01 2018-12-31 C007565 5-13 2018-01-01 2018-12-31 C007565 11-24 2018-01-01 2018-12-31 C007565 0-27 2018-01-01 2018-12-31 C007565 3-7 2018-01-01 2018-12-31 C007565 15-24 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-36 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 2-34 2018-12-31 C007565 10-11 2018-01-01 2018-12-31 C007565 4-36 2018-01-01 2018-12-31 C007565 7-30 2018-01-01 2018-12-31 C007565 1-4 2018-12-31 C007565 18-19 2018-01-01 2018-12-31 C007565 5-21 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 0-15 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 3-4 2018-12-31 C007565 13-29 2018-12-31 C007565 0-31 2018-01-01 2018-12-31 C007565 11-9 2018-12-31 C007565 ferc:ElectricUtilityMember 0-6 2017-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 14-21 2018-01-01 2018-12-31 C007565 12-14 2018-12-31 C007565 4-30 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 8-37 2018-01-01 2018-12-31 C007565 15-4 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-5 2018-01-01 2018-12-31 C007565 15-7 2018-01-01 2018-12-31 C007565 8-21 2018-01-01 2018-12-31 C007565 0-69 2017-01-01 2017-12-31 C007565 4-3 2018-01-01 2018-12-31 C007565 12-13 2018-01-01 2018-12-31 C007565 18-13 2018-01-01 2018-12-31 C007565 5-14 2018-12-31 C007565 3-1 2018-01-01 2018-12-31 C007565 1-26 2018-01-01 2018-12-31 C007565 1-33 2018-01-01 2018-12-31 C007565 13-23 2018-01-01 2018-12-31 C007565 12-16 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-21 2018-01-01 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 6-18 2018-12-31 C007565 12-27 2018-01-01 2018-12-31 C007565 1-11 2018-01-01 2018-12-31 C007565 4-30 2018-01-01 2018-12-31 C007565 6-10 2018-01-01 2018-12-31 C007565 17-23 2018-12-31 C007565 ferc:ElectricUtilityMember 0-41 2018-01-01 2018-12-31 C007565 18-28 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 0-13 2018-12-31 C007565 3-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-35 2018-12-31 C007565 10-7 2018-01-01 2018-12-31 C007565 9-6 2018-12-31 C007565 6-34 2018-01-01 2018-12-31 C007565 16-26 2018-12-31 C007565 5-26 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-2 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 0-3 2017-12-31 C007565 8-29 2018-01-01 2018-12-31 C007565 10-29 2018-01-01 2018-12-31 C007565 0-38 2018-12-31 C007565 ferc:OtherUtilityMember 2018-01-01 2018-12-31 C007565 2-3 2018-01-01 2018-12-31 C007565 0-29 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-15 2018-01-01 2018-12-31 C007565 14-22 2018-01-01 2018-12-31 C007565 12-23 2018-01-01 2018-12-31 C007565 0-2 2018-12-31 C007565 0-35 2018-01-01 2018-12-31 C007565 0-23 2018-01-01 2018-12-31 C007565 2-31 2018-01-01 2018-12-31 C007565 15-13 2018-12-31 C007565 11-21 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 3-37 2018-01-01 2018-12-31 C007565 8-37 2018-12-31 C007565 0-21 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 1-27 2018-01-01 2018-12-31 C007565 3-23 2018-01-01 2018-12-31 C007565 4 2018-01-01 2018-12-31 C007565 6-11 2018-12-31 C007565 1-11 2018-01-01 2018-12-31 C007565 2-9 2018-01-01 2018-12-31 C007565 8-13 2018-01-01 2018-12-31 C007565 14-15 2018-01-01 2018-12-31 C007565 7-9 2018-01-01 2018-12-31 C007565 0-17 2017-12-31 C007565 7-31 2018-01-01 2018-12-31 C007565 11-8 2018-12-31 C007565 0-9 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 8-28 2018-12-31 C007565 1-20 2018-01-01 2018-12-31 C007565 14-14 2018-12-31 C007565 0-27 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-12 2018-01-01 2018-12-31 C007565 1-1 2018-12-31 C007565 3-3 2018-12-31 C007565 7-10 2018-01-01 2018-12-31 C007565 7-2 2018-12-31 C007565 6-30 2018-01-01 2018-12-31 C007565 2-14 2018-01-01 2018-12-31 C007565 15-18 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-32 2018-12-31 C007565 2-33 2018-01-01 2018-12-31 C007565 17-19 2018-12-31 C007565 1-1 2018-01-01 2018-12-31 C007565 6-25 2018-01-01 2018-12-31 C007565 1-39 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-34 2018-12-31 C007565 0-34 2018-12-31 C007565 1-7 2018-01-01 2018-12-31 C007565 10-14 2018-01-01 2018-12-31 C007565 15-20 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-26 2018-12-31 C007565 ferc:ElectricUtilityMember 0-14 2018-01-01 2018-12-31 C007565 18-40 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-23 2018-01-01 2018-12-31 C007565 1-31 2018-01-01 2018-12-31 C007565 5-10 2018-12-31 C007565 12-5 2018-01-01 2018-12-31 C007565 6-31 2018-01-01 2018-12-31 C007565 ScheduleGeneratingPlantStatisticsAbstract 2018-01-01 2018-12-31 C007565 2-14 2018-01-01 2018-12-31 C007565 3-27 2018-12-31 C007565 13-34 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-31 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 8-24 2018-01-01 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 1-6 2018-01-01 2018-12-31 C007565 3-22 2018-01-01 2018-12-31 C007565 2-24 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-22 2018-01-01 2018-12-31 C007565 2-8 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 3-8 2018-01-01 2018-12-31 C007565 1-20 2018-01-01 2018-12-31 C007565 10-22 2018-01-01 2018-12-31 C007565 2-26 2018-12-31 C007565 14-15 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-13 2018-01-01 2018-12-31 C007565 11-33 2018-01-01 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-7 2018-01-01 2018-12-31 C007565 0-17 2018-01-01 2018-12-31 C007565 1-13 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-29 2018-01-01 2018-12-31 C007565 1-1 2018-12-31 C007565 12-8 2018-12-31 C007565 ferc:ElectricUtilityMember 1-28 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-27 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-28 2018-12-31 C007565 17-33 2018-12-31 C007565 3-28 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-9 2018-01-01 2018-12-31 C007565 3-19 2018-01-01 2018-12-31 C007565 3-19 2018-12-31 C007565 6-29 2018-01-01 2018-12-31 C007565 13-30 2018-01-01 2018-12-31 C007565 1-7 2018-01-01 2018-12-31 C007565 1-32 2018-12-31 C007565 7-11 2018-01-01 2018-12-31 C007565 3-15 2018-12-31 C007565 1-38 2018-12-31 C007565 10-2 2018-01-01 2018-12-31 C007565 ferc:AllocationOfPayrollChargedForClearingAccountsMember 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-3 2018-01-01 2018-12-31 C007565 2-19 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-10 2018-12-31 C007565 0-17 2018-12-31 C007565 2-13 2018-01-01 2018-12-31 C007565 13-13 2018-12-31 C007565 ferc:ElectricUtilityMember 2-4 2018-12-31 C007565 11-35 2018-01-01 2018-12-31 C007565 17-26 2018-01-01 2018-12-31 C007565 0-32 2018-01-01 2018-12-31 C007565 1-34 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 6-27 2018-12-31 C007565 0-6 2017-12-31 C007565 0-14 2018-12-31 C007565 0-29 2018-01-01 2018-12-31 C007565 3-32 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-3 2018-12-31 C007565 ferc:ElectricUtilityMember 1-36 2018-12-31 C007565 0-14 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-3 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 7-29 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-24 2018-12-31 C007565 5-16 2018-12-31 C007565 16-15 2018-12-31 C007565 5-9 2018-01-01 2018-12-31 C007565 14-25 2018-01-01 2018-12-31 C007565 11-17 2018-01-01 2018-12-31 C007565 7-10 2018-12-31 C007565 ferc:LandAndRightsMember 0-15 2018-12-31 C007565 2-38 2018-01-01 2018-12-31 C007565 11-6 2018-01-01 2018-12-31 C007565 3-29 2018-12-31 C007565 ferc:ElectricUtilityMember 0-19 2018-01-01 2018-12-31 C007565 8-5 2018-12-31 C007565 13-20 2018-12-31 C007565 4-40 2018-01-01 2018-12-31 C007565 15-14 2018-01-01 2018-12-31 C007565 0-35 2018-12-31 C007565 0-20 2018-01-01 2018-12-31 C007565 2-5 2018-01-01 2018-12-31 C007565 12-30 2018-01-01 2018-12-31 C007565 5-40 2018-01-01 2018-12-31 C007565 9-11 2018-01-01 2018-12-31 C007565 6-16 2018-12-31 C007565 4-7 2018-01-01 2018-12-31 C007565 0-19 2018-01-01 2018-12-31 C007565 17-1 2018-01-01 2018-12-31 C007565 2-13 2018-01-01 2018-12-31 C007565 ferc:OperatingUtilityMember 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 17-23 2018-01-01 2018-12-31 C007565 13-32 2018-12-31 C007565 1-26 2018-01-01 2018-12-31 C007565 5-34 2018-01-01 2018-12-31 C007565 1-12 2018-01-01 2018-12-31 C007565 0-31 2018-01-01 2018-12-31 C007565 10-5 2018-01-01 2018-12-31 C007565 14-6 2018-12-31 C007565 4-18 2018-01-01 2018-12-31 C007565 13-34 2018-12-31 C007565 16-2 2018-12-31 C007565 ScheduleTransmissionOfElectricityByIsoOrRtoAbstract 2018-01-01 2018-12-31 C007565 17-18 2018-01-01 2018-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 9-38 2018-12-31 C007565 1-34 2018-01-01 2018-12-31 C007565 19-8 2018-12-31 C007565 15-29 2018-12-31 C007565 1-23 2018-01-01 2018-12-31 C007565 16-20 2018-12-31 C007565 ScheduleSalesOfElectricityByRateSchedulesAbstract 2018-01-01 2018-12-31 C007565 4-23 2018-12-31 C007565 0-14 2017-12-31 C007565 0-11 2018-01-01 2018-12-31 C007565 16-1 2018-12-31 C007565 4-24 2018-01-01 2018-12-31 C007565 8-25 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-9 2018-01-01 2018-12-31 C007565 3-13 2018-01-01 2018-12-31 C007565 16-27 2018-01-01 2018-12-31 C007565 7-33 2018-01-01 2018-12-31 C007565 Composite-0 Oklaunion-0 2018-01-01 2018-12-31 C007565 8-16 2018-01-01 2018-12-31 C007565 14-15 2018-01-01 2018-12-31 C007565 14-2 2018-01-01 2018-12-31 C007565 4-21 2018-01-01 2018-12-31 C007565 0-35 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-19 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 0-4 2018-01-01 2018-12-31 C007565 1-9 2018-01-01 2018-12-31 C007565 0-9 2017-12-31 C007565 0-17 2018-01-01 2018-12-31 C007565 18-25 2018-12-31 C007565 ScheduleExtraordinaryPropertyLossesAbstract 2018-01-01 2018-12-31 C007565 9-5 2018-12-31 C007565 15-30 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-13 2018-01-01 2018-12-31 C007565 12-13 2018-12-31 C007565 16-40 2018-12-31 C007565 6-15 2018-01-01 2018-12-31 C007565 4-38 2018-12-31 C007565 3-4 2018-01-01 2018-12-31 C007565 14-23 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 5-27 2018-12-31 C007565 12-25 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 2-20 2018-12-31 C007565 1-8 2018-01-01 2018-12-31 C007565 14-38 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-18 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-22 2018-12-31 C007565 9-23 2018-01-01 2018-12-31 C007565 13-6 2018-12-31 C007565 8-14 2018-01-01 2018-12-31 C007565 13-13 2018-01-01 2018-12-31 C007565 0-16 2018-01-01 2018-12-31 C007565 14-1 2018-01-01 2018-12-31 C007565 0-11 2018-12-31 C007565 8-28 2018-01-01 2018-12-31 C007565 1-29 2018-01-01 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:CurrentYearMember 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-3 2018-01-01 2018-12-31 C007565 13-3 2018-01-01 2018-12-31 C007565 14-16 2018-01-01 2018-12-31 C007565 5-21 2018-12-31 C007565 16-11 2018-01-01 2018-12-31 C007565 1-33 2018-01-01 2018-12-31 C007565 5-3 2018-01-01 2018-12-31 C007565 12-36 2018-12-31 C007565 5-24 2018-01-01 2018-12-31 C007565 0-12 2018-01-01 2018-12-31 C007565 14-27 2018-01-01 2018-12-31 C007565 8-38 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-33 2018-01-01 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-11 2018-12-31 C007565 0-10 2018-12-31 C007565 4-9 2018-01-01 2018-12-31 C007565 12-34 2018-01-01 2018-12-31 C007565 6-13 2018-01-01 2018-12-31 C007565 1-12 2018-12-31 C007565 18-17 2018-01-01 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 14-12 2018-01-01 2018-12-31 C007565 10-11 2018-01-01 2018-12-31 C007565 11-35 2018-01-01 2018-12-31 C007565 17-17 2018-12-31 C007565 ferc:ElectricUtilityMember 0-29 2018-01-01 2018-12-31 C007565 0-10 2017-12-31 C007565 ferc:TransmissionStudiesMember 2-2 2018-01-01 2018-12-31 C007565 14-30 2018-12-31 C007565 1-3 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 1-16 2018-01-01 2018-12-31 C007565 11-1 2018-12-31 C007565 ferc:ElectricUtilityMember 2-2 2018-12-31 C007565 15-6 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-38 2018-01-01 2018-12-31 C007565 0-31 2018-01-01 2018-12-31 C007565 0-2 2018-12-31 C007565 13-27 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 1-25 2018-01-01 2018-12-31 C007565 2-26 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-3 2018-01-01 2018-12-31 C007565 1-25 2018-01-01 2018-12-31 C007565 0-2 2018-12-31 C007565 0-40 2018-01-01 2018-12-31 C007565 3-30 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-42 2018-12-31 C007565 4-20 2018-01-01 2018-12-31 C007565 11-12 2018-01-01 2018-12-31 C007565 8-4 2018-01-01 2018-12-31 C007565 16-40 2018-01-01 2018-12-31 C007565 15-12 2018-01-01 2018-12-31 C007565 14-18 2018-12-31 C007565 14-8 2018-12-31 C007565 0-22 2018-12-31 C007565 16-3 2018-01-01 2018-12-31 C007565 19-1 2018-01-01 2018-12-31 C007565 11-25 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-4 2018-01-01 2018-12-31 C007565 11-23 2018-01-01 2018-12-31 C007565 1-10 2018-01-01 2018-12-31 C007565 13-11 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-17 2018-01-01 2018-12-31 C007565 14-12 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-7 2018-01-01 2018-12-31 C007565 4-7 2018-01-01 2018-12-31 C007565 7-26 2018-01-01 2018-12-31 C007565 10-17 2018-12-31 C007565 16-25 2018-12-31 C007565 4-8 2018-01-01 2018-12-31 C007565 17-37 2018-01-01 2018-12-31 C007565 5-32 2018-01-01 2018-12-31 C007565 2-23 2018-01-01 2018-12-31 C007565 0-4 2017-12-31 C007565 ferc:TransmissionStudiesMember 1-20 2018-01-01 2018-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 8-15 2018-01-01 2018-12-31 C007565 10-11 2018-12-31 C007565 10-13 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-13 2018-01-01 2018-12-31 C007565 4-28 2018-12-31 C007565 2-26 2018-01-01 2018-12-31 C007565 0-13 2018-01-01 2018-12-31 C007565 7-25 2018-01-01 2018-12-31 C007565 1-14 2018-01-01 2018-12-31 C007565 2-19 2018-01-01 2018-12-31 C007565 0-9 2018-12-31 C007565 0-28 2018-01-01 2018-12-31 C007565 1-9 2018-01-01 2018-12-31 C007565 11-26 2018-12-31 C007565 13-14 2018-01-01 2018-12-31 C007565 18-40 2018-12-31 C007565 16-31 2018-01-01 2018-12-31 C007565 ferc:JulyMember 0 2018-01-01 2018-12-31 C007565 9-23 2018-12-31 C007565 2-12 2018-01-01 2018-12-31 C007565 0-32 2018-01-01 2018-12-31 C007565 2-34 2018-01-01 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 0-86 2018-01-01 2018-12-31 C007565 9-10 2018-01-01 2018-12-31 C007565 2-40 2018-01-01 2018-12-31 C007565 4-27 2018-12-31 C007565 2-30 2018-01-01 2018-12-31 C007565 0-34 2018-01-01 2018-12-31 C007565 2-2 2018-01-01 2018-12-31 C007565 1-27 2018-01-01 2018-12-31 C007565 2-6 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 7-28 2018-01-01 2018-12-31 C007565 6-26 2018-01-01 2018-12-31 C007565 12-7 2018-01-01 2018-12-31 C007565 11-10 2018-01-01 2018-12-31 C007565 17-21 2018-01-01 2018-12-31 C007565 0-6 2018-01-01 2018-12-31 C007565 1-3 2018-01-01 2018-12-31 C007565 13-15 2018-01-01 2018-12-31 C007565 13-12 2018-01-01 2018-12-31 C007565 2-28 2018-01-01 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 ferc:LandAndRightsMember 0-9 2018-12-31 C007565 2-34 2018-01-01 2018-12-31 C007565 3-31 2018-01-01 2018-12-31 C007565 13-37 2018-12-31 C007565 13-33 2018-01-01 2018-12-31 C007565 10-19 2018-01-01 2018-12-31 C007565 3-29 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-27 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-15 2018-01-01 2018-12-31 C007565 5 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 13-35 2018-12-31 C007565 ferc:ElectricUtilityMember 0-26 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 0-12 2018-01-01 2018-12-31 C007565 7-32 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2017-01-01 2017-12-31 C007565 14-23 2018-01-01 2018-12-31 C007565 2-1 2018-01-01 2018-12-31 C007565 1-12 2018-01-01 2018-12-31 C007565 2-25 2018-01-01 2018-12-31 C007565 14-37 2018-12-31 C007565 0-80 2018-01-01 2018-12-31 C007565 6-34 2018-12-31 C007565 19-9 2018-01-01 2018-12-31 C007565 2-6 2018-01-01 2018-12-31 C007565 18-2 2018-01-01 2018-12-31 C007565 16-23 2018-12-31 C007565 10-9 2018-01-01 2018-12-31 C007565 18-35 2018-01-01 2018-12-31 C007565 5-3 2018-01-01 2018-12-31 C007565 5-5 2018-01-01 2018-12-31 C007565 14-32 2018-01-01 2018-12-31 C007565 3-36 2018-12-31 C007565 11-40 2018-12-31 C007565 1-33 2018-12-31 C007565 11-9 2018-01-01 2018-12-31 C007565 2-3 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-17 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 4-6 2018-12-31 C007565 ferc:ElectricUtilityMember 1-2 2018-01-01 2018-12-31 C007565 1-30 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 SchedulePurchasesSalesOfAncillaryServicesAbstract 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-5 2018-12-31 C007565 1-35 2018-01-01 2018-12-31 C007565 8-32 2018-01-01 2018-12-31 C007565 ferc:TransmissionStudiesMember 2-14 2018-01-01 2018-12-31 C007565 7-20 2018-01-01 2018-12-31 C007565 0-7 2018-01-01 2018-12-31 C007565 4-31 2018-01-01 2018-12-31 C007565 0-15 2017-12-31 C007565 16-25 2018-01-01 2018-12-31 C007565 0-22 2018-01-01 2018-12-31 C007565 0-35 2018-01-01 2018-12-31 C007565 0-6 2017-12-31 C007565 0-15 2018-01-01 2018-12-31 C007565 0-17 2018-01-01 2018-12-31 C007565 0-30 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-23 2018-12-31 C007565 6-10 2018-12-31 C007565 ferc:ElectricUtilityMember 1-25 2018-01-01 2018-12-31 C007565 12-3 2018-01-01 2018-12-31 C007565 1-7 2018-12-31 C007565 16-13 2018-01-01 2018-12-31 C007565 0-32 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-7 2018-01-01 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 8-10 2018-01-01 2018-12-31 C007565 13-22 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:NextTwelveMonthsMember 2018-12-31 C007565 0-10 2018-01-01 2018-12-31 C007565 6-24 2018-01-01 2018-12-31 C007565 6-1 2018-01-01 2018-12-31 C007565 0-5 2017-12-31 C007565 1-5 2018-01-01 2018-12-31 C007565 1-30 2018-01-01 2018-12-31 C007565 16-38 2018-01-01 2018-12-31 C007565 3-12 2018-01-01 2018-12-31 C007565 0-3 2018-01-01 2018-12-31 C007565 0-78 2018-01-01 2018-12-31 C007565 0-24 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 0-11 2018-01-01 2018-12-31 C007565 6-2 2018-12-31 C007565 3-26 2018-12-31 C007565 9-14 2018-01-01 2018-12-31 C007565 8-10 2018-12-31 C007565 0-8 2018-01-01 2018-12-31 C007565 17-8 2018-01-01 2018-12-31 C007565 10-18 2018-01-01 2018-12-31 C007565 9-22 2018-12-31 C007565 3-25 2018-01-01 2018-12-31 C007565 2-6 2018-01-01 2018-12-31 C007565 4-17 2018-01-01 2018-12-31 C007565 16-2 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 7-13 2018-01-01 2018-12-31 C007565 13-35 2018-01-01 2018-12-31 C007565 1-4 2018-01-01 2018-12-31 C007565 19-3 2018-12-31 C007565 9-20 2018-01-01 2018-12-31 C007565 12-30 2018-12-31 C007565 3-2 2018-01-01 2018-12-31 C007565 16-6 2018-01-01 2018-12-31 C007565 0-5 2018-01-01 2018-12-31 C007565 14-4 2018-12-31 C007565 17-27 2018-01-01 2018-12-31 C007565 16-5 2018-12-31 C007565 6-26 2018-01-01 2018-12-31 C007565 9-18 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 1-11 2018-01-01 2018-12-31 C007565 13-24 2018-12-31 C007565 4-17 2018-01-01 2018-12-31 C007565 10-36 2018-12-31 C007565 12-40 2018-12-31 C007565 3-38 2018-01-01 2018-12-31 C007565 15-31 2018-01-01 2018-12-31 C007565 12-10 2018-12-31 C007565 9-9 2018-12-31 C007565 12-19 2018-01-01 2018-12-31 C007565 8-26 2018-12-31 C007565 16-1 2018-01-01 2018-12-31 C007565 1-18 2018-01-01 2018-12-31 C007565 5-30 2018-01-01 2018-12-31 C007565 6-1 2018-01-01 2018-12-31 C007565 14-25 2018-01-01 2018-12-31 C007565 0-11 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-3 2018-12-31 C007565 2-4 2018-01-01 2018-12-31 C007565 8-39 2018-01-01 2018-12-31 C007565 9-2 2018-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 16-26 2018-01-01 2018-12-31 C007565 2-31 2018-01-01 2018-12-31 C007565 2-23 2018-01-01 2018-12-31 C007565 10-34 2018-01-01 2018-12-31 C007565 10-14 2018-01-01 2018-12-31 C007565 15-16 2018-01-01 2018-12-31 C007565 3-18 2018-01-01 2018-12-31 C007565 0-18 2017-01-01 2017-12-31 C007565 0-26 2018-01-01 2018-12-31 C007565 16-8 2018-01-01 2018-12-31 C007565 2-16 2018-01-01 2018-12-31 C007565 0-1 2018-01-01 2018-12-31 C007565 0-21 2018-01-01 2018-12-31 C007565 12-28 2018-12-31 C007565 0-5 2017-12-31 C007565 2-2 2018-01-01 2018-12-31 C007565 ferc:SulfurDioxideMember ferc:ThreeYearsMember 2017-12-31 C007565 3-13 2018-01-01 2018-12-31 C007565 7-3 2018-01-01 2018-12-31 C007565 ferc:ElectricUtilityMember 2-22 2018-12-31 C007565 7-40 2018-01-01 2018-12-31 C007565 0-12 2018-12-31 C007565 0-2 2018-01-01 2018-12-31 C007565 10-24 2018-01-01 2018-12-31 C007565 2-14 2018-01-01 2018-12-31 C007565 7-18 2018-12-31 iso4217:USD utr:MMBTU ferc:MVa iso4217:USD utr:kWh utr:MWh utr:MW iso4217:USD utr:kWh utr:kV pure utr:mi utr:Btu utr:kWh
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)

AEP Texas Inc.
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

AEP Texas Inc.
02 Year/ Period of Report


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

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

1 Riverside Plaza, Columbus, Ohio 43215-2373
05 Name of Contact Person

Kathy L. Messer
06 Title of Contact Person

Accountant
07 Address of Contact Person (Street, City, State, Zip Code)

AEP Service Corporation, 1 Riverside Plaza, Columbus, Ohio 43215-2373
08 Telephone of Contact Person, Including Area Code

(614) 716-1000
09 This Report is An Original / A Resubmission

(1)
An Original

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

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

Jeffrey Hoersdig
02 Title

Assistant Controller
03 Signature

04 Date Signed (Mo, Da, Yr)

04/11/2019
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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
7
ScheduleImportantChangesDuringTheQuarterYearAbstract
Important Changes During the Year
108
8
ScheduleComparativeBalanceSheetAbstract
Comparative Balance Sheet
110
9
ScheduleStatementOfIncomeAbstract
Statement of Income for the Year
114
Page 116 - N/A
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
N/A
16
ScheduleElectricPlantInServiceAbstract
Electric Plant in Service
204
17
ScheduleElectricPropertyLeasedToOthersAbstract
Electric Plant Leased to Others
213
N/A
18
ScheduleElectricPlantHeldForFutureUseAbstract
Electric Plant Held for Future Use
214
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
N/A
25
ScheduleUnrecoveredPlantAndRegulatoryStudyCostsAbstract
Unrecovered Plant and Regulatory Study Costs
230b
N/A
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
N/A
31
ScheduleOtherPaidInCapitalAbstract
Other Paid-in Capital
253
32
ScheduleCapitalStockExpenseAbstract
Capital Stock Expense
254b
N/A
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
N/A
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
N/A
44
ScheduleSalesOfElectricityByRateSchedulesAbstract
Sales of Electricity by Rate Schedules
304
N/A
45
ScheduleSalesForResaleAbstract
Sales for Resale
310
46
ScheduleElectricOperationsAndMaintenanceExpensesAbstract
Electric Operation and Maintenance Expenses
320
47
SchedulePurchasedPowerAbstract
Purchased Power
326
N/A
48
ScheduleTransmissionOfElectricityForOthersAbstract
Transmission of Electricity for Others
328
49
ScheduleTransmissionOfElectricityByIsoOrRtoAbstract
Transmission of Electricity by ISO/RTOs
331
N/A
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
N/A
57
ScheduleAmountsIncludedInIsoOrRtoSettlementAbstract
Amounts included in ISO/RTO Settlement Statements
397
N/A
58
SchedulePurchasesSalesOfAncillaryServicesAbstract
Purchase and Sale of Ancillary Services
398
N/A
59
ScheduleMonthlyTransmissionSystemPeakLoadAbstract
Monthly Transmission System Peak Load
400
60
ScheduleMonthlyIsoOrRtoTransmissionSystemPeakLoadAbstract
Monthly ISO/RTO Transmission System Peak Load
400a
N/A
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
N/A
65
SchedulePumpedStorageGeneratingPlantStatisticsAbstract
Pumped Storage Generating Plant Statistics
408
N/A
66
ScheduleGeneratingPlantStatisticsAbstract
Generating Plant Statistics Pages
410
N/A
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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.

Jeffrey W Hoersdig, Assistant Controller 212 e. 6th Street Tulsa, Oklahoma 740119

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

State of Texas December 31,2016

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.

AEP Texas is a public utility engaged in the purchase, sale, transmission and distribution of electricity in the State of Texas. Under the Texas electric restructuring legislation, we completed the final stage of exiting the generation business and have ceased serving retail load. AEP Texas' remaining generating capacity that is not deactivated has been transferred to an affiliated company at our cost pursuant to a 20-year agreement.
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
03/02/2017

(2)
No


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.
In 2016, AEP Utilities, Inc. (formerly Central and South West Corporation, a registered holding company) owned 100% of the outstanding shares of common stock of both AEP Texas Central Company and AEP Texas North Company. On December 31, 2016, those companies merged into AEP Utilities, Inc., and AEP Utilities, Inc. name was changed to AEP Texas. American Electric Power Company, Inc., a registered holding company, owned 100% of AEP Utilities, Inc.'s outstanding shares of common stock during 2016 and owns 100% of AEP Texas outstanding common stock.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
AEP Texas North Generation Company, LLC
Non Regulated Generation
100
2
AEP Texas Central Transition Funding LLC
Financing
100
3
AEP Texas Central Transition Funding II LLC
Financing
100
4
AEP Texas Central Transition Funding III LLC
Financing
100


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
(a)
See Footnote


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OfficerTitle

 

Summary Compensation Table

The following table provides summary information concerning compensation earned by our Chief Executive Officer, our Chief Financial Officer and the three other most highly compensated executive officers, to whom we refer collectively as the named executive officers.

 

 

 

 

 

 

 

 

 

 

Name and Principal
Position

Year

Salary ($)(1)

Bonus ($)

Stock Awards

($)(2)

Non-Equity

Incentive

Plan

Compensation

($)(3)

Change

in

Pension

Value

and
Nonqualified

Deferred

Compensation

Earnings

($)(4)

All

Other

Compensation

($)(5)

Total

($)

Nicholas K. Akins—

 

 

 

 

 

 

 

 

Chairman of the Board and Chief Executive Officer

2018

1,415,423

7,564,313

2,900,000

207,401

114,891

12,202,028

Brian X. Tierney—

 

 

 

 

 

 

 

 

Executive Vice President and Chief Financial Officer

2018

771,958

1,945,785

890,000

0

59,547

3,667,290

David M. Feinberg—

 

 

 

 

 

 

 

 

Executive Vice President, General Counsel and Secretary

2018

650,492

1,362,082

655,000

25,724

48,106

2,741,404

Lisa M. Barton—

 

 

 

 

 

 

 

 

Executive Vice President- Transmission

2018

571,189

1,167,470

575,000

40,845

55,264

2,409,768

Lana L. Hillebrand—

 

 

 

 

 

 

 

 

Executive Vice President- Chief Administrative Officer

2018

597,289

972,924

600,000

47,656

57,530

2,275,399

 

  1. Amounts in the salary column are composed of executive salaries earned for the year shown, which include 261 days of pay for 2018. This is one day more than the standard 260 calendar work days and holidays in a year.

 

  1. The amounts reported in this column reflect the aggregate grant date fair value calculated in accordance with FASB ASC Topic 718 of the performance units and restricted stock units (RSUs) granted under our Long-Term Incentive Plan. See Note 15 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2018 for a discussion of the relevant assumptions used in calculating these amounts. The value realized for the performance units, if any, will depend on the Company’s performance during a three-year performance period. The potential payout can range from 0 percent to 200 percent of the target number of performance units, plus any dividend equivalents.

 

The value of the 2018 performance units will be based on two equally weighted measures: a Board approved cumulative operating earnings per share measure (Cumulative EPS) and a total shareholder return measure (Relative TSR). The grant date fair value of the 2018 performance units that are based on Cumulative EPS was computed in accordance with FASB ASC Topic 718 and was measured based on the closing price of AEP’s common stock on the date of grant. The maximum amount payable for the 2018 performance units that are based on Cumulative EPS is equal to: $5,831,240 for Mr. Akins; $1,499,965 for Mr. Tierney; $1,049,996 for Mr. Feinberg; $900,006 for Ms. Barton and $750,016 for Ms. Hillebrand. The grant date fair value of the 2018 performance units that are based on Relative TSR is calculated using a Monte-Carlo model as of the date of grant, in accordance with FASB ASC Top 718. As the performance units that are based on Relative TSR are subject to market conditions as defined under FASB ASC Topic 718, they had no maximum grant date fair values that differed from the grant date fair values presented in the table.

The performance units granted in 2018 will settle in AEP shares. Because the 2018 performance units are to be settled in AEP shares and the Relative TSR measure is a market condition, the maximum value is factored into the calculation of the grant date fair value.    

 

  1. The amounts shown in this column are annual incentive compensation paid for the year shown. At the outset of each year, the HR Committee sets annual incentive targets and performance criteria that are used after year-end to determine if and the extent to which executive officers may receive annual incentive award payments.

 

 

  1. The amounts shown in this column are attributable to the increase in the actuarial values of each of the named executive officer’s combined benefits under AEP’s qualified and non-qualified defined benefit plans determined using interest rate and mortality assumptions consistent with those used in the Company’s financial statements. See Note 8 to the Consolidated Financial Statements included in our Form 10-K for the year ended December 31, 2018 for a discussion of the relevant assumptions.

 

(5) Amounts shown in the All Other Compensation column for 2018 include: (a) Company contributions to the Company’s Retirement Savings Plan, (b) Company contributions to the Company’s Supplemental Retirement Savings Plan and (c) perquisites. The amounts are listed in the following table:

 

 

 

 

 

 

 

Type

Nicholas K.
Akins

 

Brian X.
Tierney

 

David M.
Feinberg

 

Lisa M.
Barton

 

Lana L.
Hillebrand

 

Retirement Savings Plan Match

$ 12,141

$ 12,375

$ 12,375

$ 12,375

$ 12,375

Supplemental Retirement Savings Plan Match

$ 77,625

$ 47,172

$ 23,552

$ 29,217

$ 31,244

Perquisites

$ 25,125

$ 0

$ 12,179

$ 13,672

$ 13,911

Total

$     114,891

$     59,547

$     48,106

$     55,264

$      57,530

     Perquisites provided in 2018 included: financial counseling and tax preparation services, and, for Mr. Akins, director’s accidental death insurance premium. Executive officers may also have the occasional personal use of event tickets when such tickets are not being used for business purposes, however, there is no associated incremental cost. From time to time executive officers may receive customary gifts from third parties that sponsor sporting events (subject to our policies on conflicts of interest).

Although Mr. Akins has entered into an Aircraft Time Sharing Agreement that allows him to use our corporate aircraft for personal use for a limited number of hours each year, Mr. Akins did not use our corporate aircraft for personal use during 2018. The Aircraft Time Sharing Agreement requires Mr. Akins to reimburse the Company for the cost of his personal use of corporate aircraft in accordance with limits set forth in Federal Aviation Administration regulations. The amount of such reimbursements are expected to exceed the aggregate incremental cost of such flights.

 


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Nicholas K. Akins, Chairman of the Board and
Columbus, Ohio
2
Chief Executive Officer
3
Lisa M. Barton, Vice President
Columbus, Ohio
4
David M. Feinberg, Secretary
Columbus, Ohio
5
Lana L. Hillebrand, Vice President
Columbus, Ohio
6
Mark C. McCullough, Vice President
Columbus, Ohio
7
Paul Chodak III, Vice President
Columbus, Ohio
8
Brian X. Tierney, Vice President and
Columbus, Ohio
9
Chief Financial Officer
10
Charles R Patton, Vice President
Columbus, Ohio
11
The Respondent does not have an Executive Committee


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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 (Checked by default - Not explicitly defined)
  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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.

1.

Date Acquired

 

Period of Franchise &

 

 

Or Extended

Community

Termination

Consideration

 

Renewed on

Karnes City, Karnes

Thirty (30) year franchise

 

 

May 22, 2018

County, Texas

renewal expiring on December 13, 2048

None

 

Renewed on

City of Kenedy

Thirty (30) year franchise

 

 

May 8, 2018

Karnes County, Texas

renewal expiring on December 13, 2048

None

 

Renewed on

City of Charlotte;

Thirty (30) year franchise

 

 

May 10, 2018

Atascosa County, Texas

renewal expiring on October 13, 2048

None

 

Renewed on

City of Nordheim;

Thirty (30) year franchise

 

 

May 29, 2018

Dewitt County, Texas

renewal expiring on December 19, 2048

None

 

Renewed on

City of Eagle Lake;

Thirty (30) year franchise

 

 

July 10, 2018

Colorado County, Texas

renewal expiring on December 13, 2048

None

 

Renewed on

City of Portland;

Thirty (30) year franchise

 

 

September 4, 2018

San Patricio, Texas

renewal expiring on November 1, 2048

None

 

Renewed on

City of Munday;

Twenty-five (25) year franchise

 

 

August 14, 2018

Knox County, Texas

renewal expiring on August 13, 2043

None

 

Renewed on

City of Sinton;

Thirty (30) year franchise

 

 

September 11, 2018

San Patricio County, Texas

renewal expiring on November 15, 2048

None

 

Renewed on

City of Pleasanton;

Twenty-five (25) year franchise

 

 

September 6, 2018

Atascosa County, Texas

renewal expiring on September 5, 2043

None

 

Renewed on

City of George West;

Thirty (30) year franchise

 

 

September 26, 2018

Live Oak County, Texas

renewal expiring on October 17, 2048

None

 

Renewed on

City of Kingsville;

Thirty (30) year franchise

 

 

November 26, 2018

Kleberg County, Texas

renewal expiring on November 22, 2048

None

 

Renewed on

City of Palmhurst;

Twenty-five (25) year franchise

 

 

November 20, 2018

Hildalgo County, Texas

renewal expiring on May 31, 2039

None

 

effective

 

 

 

 

June 1, 2014

 

 

 

 

 

 

 

 

 

2.

None

 

 

 

 

 

 

 

 

 

 

3.

The letter with the required journal entries for the sale of the Walker County Site land, jointly owned by SWEPCo, AEP Texas, and PSO, to third parties was filed with the FERC on May 4, 2018. AEP Texas' portion of the total $11.5 million gain on sale was $2.4 million.

 

 

 

 

 

 

4.

None

 

 

 

 

 

 

 

 

 

 

5.

None

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6.

FERC Authority (Docket No. ES18-22-000)

 

 

 

$2,800,000 Letter of Credit issued by American Electric Power Company, Inc. on

 

 

behalf of AEP Texas Central Company to benefit UFG (United Fire Group) Specialty

 

 

Insurance

 

 

 

 

 

 

 

 

 

 

FERC Authority (Docket No. ES18-22-000)

 

 

 

$500,000,000 Series E, Senior Unsecured Notes, 3.95% , Due June 1, 2028

 

 

 

 

 

 

 

7.

None

 

 

 

 

 

 

 

 

 

 

8.

None

 

 

 

 

 

 

 

 

 

 

9.

Please refer to the Notes to Financial Statements Pages 122-123

 

 

 

 

 

 

 

10.

None

 

 

 

 

 

 

 

 

 

 

11.

(Reserved)

 

 

 

 

 

 

 

 

 

12.

Not Used

 

 

 

 

 

 

 

 

 

13.

Rogier, Daniel J. Elected As Vice President 12/12/2018

 

 

Chodak, Paul Elected As Vice President 4/26/2018

 

 

Strahler, Leigh Anne Elected As Vice President - Regulatory & Finance 3/10/2018

 

 

Sherwood, Julie A. Elected As Vice President 1/1/2018

 

 

Dieck, Lonni L. Resigned As Vice President & Treasurer 12/31/2018

 

 

Ford, Ronald K. Resigned As Vice President - Regulatory & Finance 5/2/2018

 

 

Pyle, Mark A. Resigned As Vice President-Tax 1/28/2018

 

 

 

 

 

 

 

14.

Proprietary capital ratio exceeds 30%

 

 

 


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
8,793,403,251
7,570,778,951
3
ConstructionWorkInProgress
Construction Work in Progress (107)
200
836,188,274
835,749,544
4
UtilityPlantAndConstructionWorkInProgress
TOTAL Utility Plant (Enter Total of lines 2 and 3)
9,629,591,525
8,406,528,495
5
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115)
200
2,284,845,318
2,183,018,567
6
UtilityPlantNet
Net Utility Plant (Enter Total of line 4 less 5)
7,344,746,207
6,223,509,928
7
NuclearFuelInProcessOfRefinementConversionEnrichmentAndFabrication
Nuclear Fuel in Process of Ref., Conv., Enrich., and Fab. (120.1)
202
8
NuclearFuelMaterialsAndAssembliesStockAccountMajorOnly
Nuclear Fuel Materials and Assemblies-Stock Account (120.2)
9
NuclearFuelAssembliesInReactorMajorOnly
Nuclear Fuel Assemblies in Reactor (120.3)
10
SpentNuclearFuelMajorOnly
Spent Nuclear Fuel (120.4)
11
NuclearFuelUnderCapitalLeases
Nuclear Fuel Under Capital Leases (120.6)
12
AccumulatedProvisionForAmortizationOfNuclearFuelAssemblies
(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)
202
13
NuclearFuelNet
Net Nuclear Fuel (Enter Total of lines 7-11 less 12)
14
UtilityPlantAndNuclearFuelNet
Net Utility Plant (Enter Total of lines 6 and 13)
7,344,746,207
6,223,509,928
15
OtherElectricPlantAdjustments
Utility Plant Adjustments (116)
16
GasStoredUndergroundNoncurrent
Gas Stored Underground - Noncurrent (117)
17
OtherPropertyAndInvestmentsAbstract
OTHER PROPERTY AND INVESTMENTS
18
NonutilityProperty
Nonutility Property (121)
2,666,998
2,691,746
19
AccumulatedProvisionForDepreciationAndAmortizationOfNonutilityProperty
(Less) Accum. Prov. for Depr. and Amort. (122)
1,006,974
763,475
20
InvestmentInAssociatedCompanies
Investments in Associated Companies (123)
21
InvestmentInSubsidiaryCompanies
Investment in Subsidiary Companies (123.1)
224
25,436,632
25,491,242
23
NoncurrentPortionOfAllowances
Noncurrent Portion of Allowances
228
24
OtherInvestments
Other Investments (124)
14,138,942
13,680,506
25
SinkingFunds
Sinking Funds (125)
26
DepreciationFund
Depreciation Fund (126)
27
AmortizationFundFederal
Amortization Fund - Federal (127)
28
OtherSpecialFunds
Other Special Funds (128)
29
SpecialFunds
Special Funds (Non Major Only) (129)
39,138,710
58,772,953
30
DerivativeInstrumentAssetsLongTerm
Long-Term Portion of Derivative Assets (175)
31
DerivativeInstrumentAssetsHedgesLongTerm
Long-Term Portion of Derivative Assets - Hedges (176)
32
OtherPropertyAndInvestments
TOTAL Other Property and Investments (Lines 18-21 and 23-31)
80,374,308
99,872,972
33
CurrentAndAccruedAssetsAbstract
CURRENT AND ACCRUED ASSETS
34
CashAndWorkingFunds
Cash and Working Funds (Non-major Only) (130)
35
Cash
Cash (131)
2,974,040
1,949,829
36
SpecialDeposits
Special Deposits (132-134)
299,186
129,786
37
WorkingFunds
Working Fund (135)
100,000
100,000
38
TemporaryCashInvestments
Temporary Cash Investments (136)
39
NotesReceivable
Notes Receivable (141)
40
CustomerAccountsReceivable
Customer Accounts Receivable (142)
108,272,661
102,745,715
41
OtherAccountsReceivable
Other Accounts Receivable (143)
1,549,179
1,133,850
42
AccumulatedProvisionForUncollectibleAccountsCredit
(Less) Accum. Prov. for Uncollectible Acct.-Credit (144)
1,287,279
652,303
43
NotesReceivableFromAssociatedCompanies
Notes Receivable from Associated Companies (145)
103,538,150
44
AccountsReceivableFromAssociatedCompanies
Accounts Receivable from Assoc. Companies (146)
15,187,240
12,262,859
45
FuelStock
Fuel Stock (151)
227
8,667,188
3,438,722
46
FuelStockExpensesUndistributed
Fuel Stock Expenses Undistributed (152)
227
158,854
142,942
47
Residuals
Residuals (Elec) and Extracted Products (153)
227
48
PlantMaterialsAndOperatingSupplies
Plant Materials and Operating Supplies (154)
227
52,796,335
52,044,738
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
53
NoncurrentPortionOfAllowances
(Less) Noncurrent Portion of Allowances
228
54
StoresExpenseUndistributed
Stores Expense Undistributed (163)
227
55
GasStoredCurrent
Gas Stored Underground - Current (164.1)
56
LiquefiedNaturalGasStoredAndHeldForProcessing
Liquefied Natural Gas Stored and Held for Processing (164.2-164.3)
57
Prepayments
Prepayments (165)
3,378,960
2,568,785
58
AdvancesForGas
Advances for Gas (166-167)
59
InterestAndDividendsReceivable
Interest and Dividends Receivable (171)
1,259,695
2,793,873
60
RentsReceivable
Rents Receivable (172)
2,605,149
2,502,446
61
AccruedUtilityRevenues
Accrued Utility Revenues (173)
70,407,414
75,791,425
62
MiscellaneousCurrentAndAccruedAssets
Miscellaneous Current and Accrued Assets (174)
4,685
63
DerivativeInstrumentAssets
Derivative Instrument Assets (175)
511,816
64
DerivativeInstrumentAssetsLongTerm
(Less) Long-Term Portion of Derivative Instrument Assets (175)
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)
266,363,937
361,002,633
68
DeferredDebitsAbstract
DEFERRED DEBITS
69
UnamortizedDebtExpense
Unamortized Debt Expenses (181)
16,506,855
14,443,247
70
ExtraordinaryPropertyLosses
Extraordinary Property Losses (182.1)
230a
71
UnrecoveredPlantAndRegulatoryStudyCosts
Unrecovered Plant and Regulatory Study Costs (182.2)
230b
72
OtherRegulatoryAssets
Other Regulatory Assets (182.3)
232
482,144,146
434,742,374
73
PreliminarySurveyAndInvestigationCharges
Prelim. Survey and Investigation Charges (Electric) (183)
31,149
328,895
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)
244
244
77
TemporaryFacilities
Temporary Facilities (185)
78
MiscellaneousDeferredDebits
Miscellaneous Deferred Debits (186)
233
2,467,651
1,401,598
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)
6,023,917
7,577,150
82
AccumulatedDeferredIncomeTaxes
Accumulated Deferred Income Taxes (190)
234
207,916,285
220,717,834
83
UnrecoveredPurchasedGasCosts
Unrecovered Purchased Gas Costs (191)
84
DeferredDebits
Total Deferred Debits (lines 69 through 83)
715,090,247
679,211,342
85
AssetsAndOtherDebits
TOTAL ASSETS (lines 14-16, 32, 67, and 84)
8,406,574,699
7,363,596,875


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
3
PreferredStockIssued
Preferred Stock Issued (204)
250
4
CapitalStockSubscribed
Capital Stock Subscribed (202, 205)
5
StockLiabilityForConversion
Stock Liability for Conversion (203, 206)
6
PremiumOnCapitalStock
Premium on Capital Stock (207)
19,482
19,482
7
OtherPaidInCapital
Other Paid-In Capital (208-211)
253
1,257,947,794
1,057,947,794
8
InstallmentsReceivedOnCapitalStock
Installments Received on Capital Stock (212)
252
9
DiscountOnCapitalStock
(Less) Discount on Capital Stock (213)
254
10
CapitalStockExpense
(Less) Capital Stock Expense (214)
254b
11
RetainedEarnings
Retained Earnings (215, 215.1, 216)
118
1,329,777,746
1,116,620,111
12
UnappropriatedUndistributedSubsidiaryEarnings
Unappropriated Undistributed Subsidiary Earnings (216.1)
118
7,964,752
8,019,361
13
ReacquiredCapitalStock
(Less) Reaquired Capital Stock (217)
250
40,947
40,947
14
NoncorporateProprietorship
Noncorporate Proprietorship (Non-major only) (218)
15
AccumulatedOtherComprehensiveIncome
Accumulated Other Comprehensive Income (219)
122(a)(b)
15,147,764
12,649,577
16
ProprietaryCapital
Total Proprietary Capital (lines 2 through 15)
2,580,521,063
2,169,916,224
17
LongTermDebtAbstract
LONG-TERM DEBT
18
Bonds
Bonds (221)
256
19
ReacquiredBonds
(Less) Reaquired Bonds (222)
256
20
AdvancesFromAssociatedCompanies
Advances from Associated Companies (223)
256
21
OtherLongTermDebt
Other Long-Term Debt (224)
256
3,114,186,630
2,644,194,500
22
UnamortizedPremiumOnLongTermDebt
Unamortized Premium on Long-Term Debt (225)
23
UnamortizedDiscountOnLongTermDebtDebit
(Less) Unamortized Discount on Long-Term Debt-Debit (226)
7,619,198
6,620,858
24
LongTermDebt
Total Long-Term Debt (lines 18 through 23)
3,106,567,432
2,637,573,642
25
OtherNoncurrentLiabilitiesAbstract
OTHER NONCURRENT LIABILITIES
26
ObligationsUnderCapitalLeaseNoncurrent
Obligations Under Capital Leases - Noncurrent (227)
23,933,909
18,527,867
27
AccumulatedProvisionForPropertyInsurance
Accumulated Provision for Property Insurance (228.1)
28
AccumulatedProvisionForInjuriesAndDamages
Accumulated Provision for Injuries and Damages (228.2)
254,933
330,091
29
AccumulatedProvisionForPensionsAndBenefits
Accumulated Provision for Pensions and Benefits (228.3)
7,688,887
11,976,525
30
AccumulatedMiscellaneousOperatingProvisions
Accumulated Miscellaneous Operating Provisions (228.4)
31
AccumulatedProvisionForRateRefunds
Accumulated Provision for Rate Refunds (229)
31,424,242
976,500
32
LongTermPortionOfDerivativeInstrumentLiabilities
Long-Term Portion of Derivative Instrument Liabilities
33
LongTermPortionOfDerivativeInstrumentLiabilitiesHedges
Long-Term Portion of Derivative Instrument Liabilities - Hedges
34
AssetRetirementObligations
Asset Retirement Obligations (230)
27,348,667
26,136,594
35
OtherNoncurrentLiabilities
Total Other Noncurrent Liabilities (lines 26 through 34)
90,650,638
57,947,577
36
CurrentAndAccruedLiabilitiesAbstract
CURRENT AND ACCRUED LIABILITIES
37
NotesPayable
Notes Payable (231)
38
AccountsPayable
Accounts Payable (232)
276,429,790
379,322,375
39
NotesPayableToAssociatedCompanies
Notes Payable to Associated Companies (233)
216,042,230
40
AccountsPayableToAssociatedCompanies
Accounts Payable to Associated Companies (234)
65,558,994
66,276,093
41
CustomerDeposits
Customer Deposits (235)
20,000
20,000
42
TaxesAccrued
Taxes Accrued (236)
262
29,585,069
35,376,376
43
InterestAccrued
Interest Accrued (237)
26,195,290
26,364,417
44
DividendsDeclared
Dividends Declared (238)
45
MaturedLongTermDebt
Matured Long-Term Debt (239)
46
MaturedInterest
Matured Interest (240)
47
TaxCollectionsPayable
Tax Collections Payable (241)
297,449
2,318
48
MiscellaneousCurrentAndAccruedLiabilities
Miscellaneous Current and Accrued Liabilities (242)
46,087,677
43,275,537
49
ObligationsUnderCapitalLeasesCurrent
Obligations Under Capital Leases-Current (243)
4,547,665
4,223,151
50
DerivativesInstrumentLiabilities
Derivative Instrument Liabilities (244)
179,158
51
LongTermPortionOfDerivativeInstrumentLiabilities
(Less) Long-Term Portion of Derivative Instrument Liabilities
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)
664,943,322
554,855,631
55
DeferredCreditsAbstract
DEFERRED CREDITS
56
CustomerAdvancesForConstruction
Customer Advances for Construction (252)
57
AccumulatedDeferredInvestmentTaxCredits
Accumulated Deferred Investment Tax Credits (255)
266
10,843,500
12,305,570
58
DeferredGainsFromDispositionOfUtilityPlant
Deferred Gains from Disposition of Utility Plant (256)
59
OtherDeferredCredits
Other Deferred Credits (253)
269
143,644,391
130,160,510
60
OtherRegulatoryLiabilities
Other Regulatory Liabilities (254)
278
688,165,365
704,857,783
61
UnamortizedGainOnReacquiredDebt
Unamortized Gain on Reaquired Debt (257)
62
AccumulatedDeferredIncomeTaxesAcceleratedAmortizationProperty
Accum. Deferred Income Taxes-Accel. Amort.(281)
272
63
AccumulatedDeferredIncomeTaxesOtherProperty
Accum. Deferred Income Taxes-Other Property (282)
844,676,506
760,871,350
64
AccumulatedDeferredIncomeTaxesOther
Accum. Deferred Income Taxes-Other (283)
276,562,482
335,108,588
65
DeferredCredits
Total Deferred Credits (lines 56 through 64)
1,963,892,244
1,943,303,801
66
LiabilitiesAndOtherCredits
TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)
8,406,574,699
7,363,596,875


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
1,322,396,025
1,263,517,167
1,322,396,025
1,263,517,167
3
OperatingExpensesAbstract
Operating Expenses
4
OperationExpense
Operation Expenses (401)
320
506,888,993
466,706,300
506,888,993
466,706,300
5
MaintenanceExpense
Maintenance Expenses (402)
320
89,429,855
75,905,562
89,429,855
75,905,562
6
DepreciationExpense
Depreciation Expense (403)
336
235,272,512
200,664,254
235,272,512
200,664,254
7
DepreciationExpenseForAssetRetirementCosts
Depreciation Expense for Asset Retirement Costs (403.1)
336
2,878,158
84,710
2,878,158
84,710
8
AmortizationAndDepletionOfUtilityPlant
Amort. & Depl. of Utility Plant (404-405)
336
24,054,567
20,553,455
24,054,567
20,553,455
9
AmortizationOfElectricPlantAcquisitionAdjustments
Amort. of Utility Plant Acq. Adj. (406)
336
10
AmortizationOfPropertyLossesUnrecoveredPlantAndRegulatoryStudyCosts
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11
AmortizationOfConversionExpenses
Amort. of Conversion Expenses (407.2)
12
RegulatoryDebits
Regulatory Debits (407.3)
9,441,783
9,459,990
9,441,783
9,459,990
13
RegulatoryCredits
(Less) Regulatory Credits (407.4)
4,745,763
4,745,763
4,745,763
4,745,763
14
TaxesOtherThanIncomeTaxesUtilityOperatingIncome
Taxes Other Than Income Taxes (408.1)
262
132,490,639
121,313,648
132,490,639
121,313,648
15
IncomeTaxesOperatingIncome
Income Taxes - Federal (409.1)
262
34,742,843
96,369,830
34,742,843
96,369,830
16
IncomeTaxesUtilityOperatingIncomeOther
Income Taxes - Other (409.1)
262
1,766,143
716,706
1,766,143
716,706
17
ProvisionsForDeferredIncomeTaxesUtilityOperatingIncome
Provision for Deferred Income Taxes (410.1)
234, 272
1,976,990,602
410,290,062
1,976,990,602
410,290,062
18
ProvisionForDeferredIncomeTaxesCreditOperatingIncome
(Less) Provision for Deferred Income Taxes-Cr. (411.1)
234, 272
1,988,530,935
326,560,157
1,988,530,935
326,560,157
19
InvestmentTaxCreditAdjustments
Investment Tax Credit Adj. - Net (411.4)
266
1,462,070
1,570,091
1,462,070
1,570,091
20
GainsFromDispositionOfPlant
(Less) Gains from Disp. of Utility Plant (411.6)
186,360
2,576,896
186,360
2,576,896
21
LossesFromDispositionOfServiceCompanyPlant
Losses from Disp. of Utility Plant (411.7)
22
GainsFromDispositionOfAllowances
(Less) Gains from Disposition of Allowances (411.8)
23
LossesFromDispositionOfAllowances
Losses from Disposition of Allowances (411.9)
24
AccretionExpense
Accretion Expense (411.10)
1,201,315
1,150,114
1,201,315
1,150,114
25
UtilityOperatingExpenses
TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)
1,020,605,002
874,852,644
1,020,605,002
874,852,644
27
NetUtilityOperatingIncome
Net Util Oper Inc (Enter Tot line 2 less 25)
301,791,023
388,664,523
301,791,023
388,664,523
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)
45,393
35
NonoperatingRentalIncome
Nonoperating Rental Income (418)
167,386
327,831
36
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings of Subsidiary Companies (418.1)
119
54,609
127,887
37
InterestAndDividendIncome
Interest and Dividend Income (419)
1,211,611
1,944,951
38
AllowanceForOtherFundsUsedDuringConstruction
Allowance for Other Funds Used During Construction (419.1)
20,024,063
6,839,780
39
MiscellaneousNonoperatingIncome
Miscellaneous Nonoperating Income (421)
2,352,490
1,059,897
40
GainOnDispositionOfProperty
Gain on Disposition of Property (421.1)
578,516
41
OtherIncome
TOTAL Other Income (Enter Total of lines 31 thru 40)
21,856,235
9,999,179
42
OtherIncomeDeductionsAbstract
Other Income Deductions
43
LossOnDispositionOfProperty
Loss on Disposition of Property (421.2)
2,880
44
MiscellaneousAmortization
Miscellaneous Amortization (425)
45
Donations
Donations (426.1)
880,284
552,067
46
LifeInsurance
Life Insurance (426.2)
247,432
625,362
47
Penalties
Penalties (426.3)
827,043
180,021
48
ExpendituresForCertainCivicPoliticalAndRelatedActivities
Exp. for Certain Civic, Political & Related Activities (426.4)
1,195,357
1,012,105
49
OtherDeductions
Other Deductions (426.5)
550,949
523,868
50
OtherIncomeDeductions
TOTAL Other Income Deductions (Total of lines 43 thru 49)
3,206,201
1,645,579
51
TaxesApplicableToOtherIncomeAndDeductionsAbstract
Taxes Applic. to Other Income and Deductions
52
TaxesOtherThanIncomeTaxesOtherIncomeAndDeductions
Taxes Other Than Income Taxes (408.2)
262
25
1,385
53
IncomeTaxesFederal
Income Taxes-Federal (409.2)
262
2,298,164
11,083,336
54
IncomeTaxesOther
Income Taxes-Other (409.2)
262
55
ProvisionForDeferredIncomeTaxesOtherIncomeAndDeductions
Provision for Deferred Inc. Taxes (410.2)
234, 272
15,300,833
4,364,508
56
ProvisionForDeferredIncomeTaxesCreditOtherIncomeAndDeductions
(Less) Provision for Deferred Income Taxes-Cr. (411.2)
234, 272
20,301,781
25,104,871
57
InvestmentTaxCreditAdjustmentsNonutilityOperations
Investment Tax Credit Adj.-Net (411.5)
58
InvestmentTaxCredits
(Less) Investment Tax Credits (420)
59
TaxesOnOtherIncomeAndDeductions
TOTAL Taxes on Other Income and Deductions (Total of lines 52-58)
2,702,759
9,655,642
60
NetOtherIncomeAndDeductions
Net Other Income and Deductions (Total of lines 41, 50, 59)
21,352,793
18,009,242
61
InterestChargesAbstract
Interest Charges
62
InterestOnLongTermDebt
Interest on Long-Term Debt (427)
121,490,766
96,437,519
63
AmortizationOfDebtDiscountAndExpense
Amort. of Debt Disc. and Expense (428)
2,975,652
2,071,544
64
AmortizationOfLossOnReacquiredDebt
Amortization of Loss on Reaquired Debt (428.1)
1,553,233
1,085,571
65
AmortizationOfPremiumOnDebtCredit
(Less) Amort. of Premium on Debt-Credit (429)
66
AmortizationOfGainOnReacquiredDebtCredit
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67
InterestOnDebtToAssociatedCompanies
Interest on Debt to Assoc. Companies (430)
2,889,771
1,852,951
68
OtherInterestExpense
Other Interest Expense (431)
1,281,964
924,493
69
AllowanceForBorrowedFundsUsedDuringConstructionCredit
(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432)
18,392,972
6,839,389
70
NetInterestCharges
Net Interest Charges (Total of lines 62 thru 69)
111,798,414
95,532,689
71
IncomeBeforeExtraordinaryItems
Income Before Extraordinary Items (Total of lines 27, 60 and 70)
211,345,402
311,141,076
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)
211,345,402
311,141,076


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
1,116,620,111
805,351,148
2
ChangesAbstract
Changes
3
AdjustmentsToRetainedEarningsAbstract
Adjustments to Retained Earnings (Account 439)
4
AdjustmentsToRetainedEarningsCreditAbstract
Adjustments to Retained Earnings Credit
4.1
AdjustmentsToRetainedEarningsCredit
Implementation of ASU 2018-02 - Remeasurement of AOCI
1,757,624
4.2
AdjustmentsToRetainedEarningsCredit
4.3
AdjustmentsToRetainedEarningsCredit
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)
1,757,624
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)
211,400,011
311,268,963
17
AppropriationsOfRetainedEarningsAbstract
Appropriations of Retained Earnings (Acct. 436)
17.1
AppropriationsOfRetainedEarnings
17.2
AppropriationsOfRetainedEarnings
17.3
AppropriationsOfRetainedEarnings
17.4
AppropriationsOfRetainedEarnings
22
AppropriationsOfRetainedEarnings
TOTAL Appropriations of Retained Earnings (Acct. 436)
23
DividendsDeclaredPreferredStockAbstract
Dividends Declared-Preferred Stock (Account 437)
23.1
DividendsDeclaredPreferredStock
23.2
DividendsDeclaredPreferredStock
23.3
DividendsDeclaredPreferredStock
23.4
DividendsDeclaredPreferredStock
23.5
DividendsDeclaredPreferredStock
29
DividendsDeclaredPreferredStock
TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30
DividendsDeclaredCommonStockAbstract
Dividends Declared-Common Stock (Account 438)
30.1
DividendsDeclaredCommonStock
30.2
DividendsDeclaredCommonStock
30.3
DividendsDeclaredCommonStock
30.4
DividendsDeclaredCommonStock
30.5
DividendsDeclaredCommonStock
36
DividendsDeclaredCommonStock
TOTAL Dividends Declared-Common Stock (Acct. 438)
37
TransfersFromUnappropriatedUndistributedSubsidiaryEarnings
Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
38
UnappropriatedRetainedEarnings
Balance - End of Period (Total 1,9,15,16,22,29,36,37)
1,329,777,746
1,116,620,111
AppropriatedRetainedEarningsAbstract
APPROPRIATED RETAINED EARNINGS (Account 215)
.1
AppropriatedRetainedEarnings
.2
AppropriatedRetainedEarnings
.3
AppropriatedRetainedEarnings
.4
AppropriatedRetainedEarnings
.5
AppropriatedRetainedEarnings
.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)
AppropriatedRetainedEarningsAmortizationReserveFederalAbstract
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46
AppropriatedRetainedEarningsAmortizationReserveFederal
TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47
AppropriatedRetainedEarningsIncludingReserveAmortization
TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
48
RetainedEarnings
TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
1,329,777,746
1,116,620,111
UnappropriatedUndistributedSubsidiaryEarningsAbstract
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly)
49
UnappropriatedUndistributedSubsidiaryEarnings
Balance-Beginning of Year (Debit or Credit)
8,019,361
8,147,248
50
EquityInEarningsOfSubsidiaryCompanies
Equity in Earnings for Year (Credit) (Account 418.1)
54,609
127,887
51
DividendsReceived
(Less) Dividends Received (Debit)
52
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
TOTAL other Changes in unappropriated undistributed subsidiary earnings for the year
52.1
ChangesUnappropriatedUndistributedSubsidiaryEarningsCredits
53
UnappropriatedUndistributedSubsidiaryEarnings
Balance-End of Year (Total lines 49 thru 52)
7,964,752
8,019,361


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
211,345,402
311,141,076
3
NoncashChargesCreditsToIncomeAbstract
Noncash Charges (Credits) to Income:
4
DepreciationAndDepletion
Depreciation and Depletion
262,205,237
221,132,999
5
NoncashAdjustmentsToCashFlowsFromOperatingActivities
Amortization of (Specify) (footnote details)
5.1
NoncashAdjustmentsToCashFlowsFromOperatingActivitiesDescription
Amortization of Regulatory Debits and Credits (Net)
4,696,020
4,714,227
8
DeferredIncomeTaxesNet
Deferred Income Taxes (Net)
16,541,281
62,989,542
9
InvestmentTaxCreditAdjustmentsNet
Investment Tax Credit Adjustment (Net)
1,462,070
1,570,091
10
NetIncreaseDecreaseInReceivablesOperatingActivities
Net (Increase) Decrease in Receivables
(b)
6,795,311
(j)
13,367,621
11
NetIncreaseDecreaseInInventoryOperatingActivities
Net (Increase) Decrease in Inventory
(c)
5,995,975
(k)
3,199,496
12
NetIncreaseDecreaseInAllowancesInventoryOperatingActivities
Net (Increase) Decrease in Allowances Inventory
13
NetIncreaseDecreaseInPayablesAndAccruedExpensesOperatingActivities
Net Increase (Decrease) in Payables and Accrued Expenses
27,101,128
5,721,578
14
NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Net (Increase) Decrease in Other Regulatory Assets
(d)
15,771,388
(l)
100,952,044
15
NetIncreaseDecreaseInOtherRegulatoryLiabilitiesOperatingActivities
Net Increase (Decrease) in Other Regulatory Liabilities
511,816
103,767
16
AllowanceForOtherFundsUsedDuringConstructionOperatingActivities
(Less) Allowance for Other Funds Used During Construction
20,024,063
6,839,780
17
UndistributedEarningsFromSubsidiaryCompaniesOperatingActivities
(Less) Undistributed Earnings from Subsidiary Companies
54,609
127,887
18
OtherAdjustmentsToCashFlowsFromOperatingActivities
Other (provide details in footnote):
18.1
OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription
(a)
Other (provide details in footnote):
25,793,558
88,427,178
22
NetCashFlowFromOperatingActivities
Net Cash Provided by (Used in) Operating Activities (Total of Lines 2 thru 21)
409,891,794
397,973,858
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)
(e)
1,448,850,545
(m)
997,704,463
27
GrossAdditionsToNuclearFuelInvestingActivities
Gross Additions to Nuclear Fuel
28
GrossAdditionsToCommonUtilityPlantInvestingActivities
Gross Additions to Common Utility Plant
29
GrossAdditionsToNonutilityPlantInvestingActivities
Gross Additions to Nonutility Plant
(n)
17,832
30
AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
(Less) Allowance for Other Funds Used During Construction
(f)
20,024,063
(o)
6,839,780
31
OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Other (provide details in footnote):
31.1
OtherConstructionAndAcquisitionOfPlantInvestmentActivitiesDescription
Acquired Assets
(g)
1,420,461
826,768
34
CashOutflowsForPlant
Cash Outflows for Plant (Total of lines 26 thru 33)
(h)
1,430,246,943
(p)
991,709,283
36
AcquisitionOfOtherNoncurrentAssets
Acquisition of Other Noncurrent Assets (d)
37
ProceedsFromDisposalOfNoncurrentAssets
Proceeds from Disposal of Noncurrent Assets (d)
1,677,661
4,419,119
39
InvestmentsInAndAdvancesToAssociatedAndSubsidiaryCompanies
Investments in and Advances to Assoc. and Subsidiary Companies
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
Contribution in Aid of Construction Proceeds
34,910,192
15,356,218
53.2
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
(Increase) Decrease in Other Special Deposits
1,357
42,686
53.3
OtherAdjustmentsToCashFlowsFromInvestmentActivitiesDescription
Notes Receivable from Associated Companies
103,538,150
103,538,150
57
CashFlowsProvidedFromUsedInInvestmentActivities
Net Cash Provided by (Used in) Investing Activities (Total of lines 34 thru 55)
1,290,122,297
1,075,514,782
59
CashFlowsFromFinancingActivitiesAbstract
Cash Flows from Financing Activities:
60
ProceedsFromIssuanceAbstract
Proceeds from Issuance of:
61
ProceedsFromIssuanceOfLongTermDebtFinancingActivities
Long-Term Debt (b)
500,000,000
760,000,000
62
ProceedsFromIssuanceOfPreferredStockFinancingActivities
Preferred Stock
63
ProceedsFromIssuanceOfCommonStockFinancingActivities
Common Stock
64
OtherAdjustmentsToCashFlowsFromFinancingActivities
Other (provide details in footnote):
64.1
OtherAdjustmentsToCashFlowsFromFinancingActivitiesDescription
Long Term Issuance Costs
5,975,838
10,385,380
66
NetIncreaseInShortTermDebt
Net Increase in Short-Term Debt (c)
67
OtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Other (provide details in footnote):
67.1
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Proceeds on Capital Leaseback
1,196,192
182,755
67.2
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Notes Payable to Associated Companies
216,042,230
67.3
DescriptionForOtherAdjustmentsByOutsideSourcesToCashFlowsFromFinancingActivities
Capital Contributions from Parent
200,000,000
200,000,000
70
CashProvidedByOutsideSources
Cash Provided by Outside Sources (Total 61 thru 69)
911,262,584
949,431,865
72
PaymentsForRetirementAbstract
Payments for Retirement of:
73
PaymentsForRetirementOfLongTermDebtFinancingActivities
Long-term Debt (b)
(i)
30,007,870
(q)
100,897,525
74
PaymentsForRetirementOfPreferredStockFinancingActivities
Preferred Stock
75
PaymentsForRetirementOfCommonStockFinancingActivities
Common Stock
76
OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Other (provide details in footnote):
76.1
DescriptionOfOtherRetirementsImpactingCashFlowsFromFinancingActivities
Notes Payable to Assciated Companies
(r)
169,504,561
78
NetDecreaseInShortTermDebt
Net Decrease in Short-Term Debt (c)
80
DividendsOnPreferredStock
Dividends on Preferred Stock
81
DividendsOnCommonStock
Dividends on Common Stock
83
CashFlowsProvidedFromUsedInFinancingActivities
Net Cash Provided by (Used in) Financing Activities (Total of lines 70 thru 81)
881,254,714
679,029,779
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)
1,024,211
1,488,855
88
CashAndCashEquivalents
Cash and Cash Equivalents at Beginning of Period
2,049,829
560,974
90
CashAndCashEquivalents
Cash and Cash Equivalents at End of Period
3,074,040
2,049,829


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: OtherAdjustmentsToCashFlowsFromOperatingActivitiesDescription

 

 

 

 

2018

 

 

2017

 

 

 

 

Cash Flow

 

 

Cash Flow

 

 

Other Operating Activities - Continued:

 

Incr / (Decr)

 

 

Incr / (Decr)

 

 

 

 

 

 

 

 

 

 

Utility Plant, Net

$

(44,950,439)

 

$

(55,747,712)

 

 

Property and Investments, Net

 

(254,696)

 

 

(1,629,335)

 

 

Special Funds

 

0

 

 

0

 

 

Margin Deposits

 

(168,043)

 

 

144,069

 

 

Mark-to-Market of Risk Management Contracts

 

690,974

 

 

(288,760)

 

 

Prepayments

 

(8,037,980)

 

 

(7,243,830)

 

 

Accrued Utility Revenues, Net

 

5,384,012

 

 

(10,956,866)

 

 

Miscellaneous Current and Accr Assets

 

229,260

 

 

0

 

 

Unamortized Debt Expense

 

2,261,673

 

 

1,168,137

 

 

Other Deferred Debits, Net

 

3,118,938

 

 

53,707,676

 

 

Proprietary Capital, Net

 

0

 

 

(49,051,069)

 

 

Other Comprehensive Income, Net

 

89,115

 

 

868,873

 

 

Unamortized Discount/Premium on Long-Term Debt

 

651,661

 

 

491,005

 

 

Accumulated Provisions - Misc

 

25,976,697

 

 

2,976,921

 

 

Current and Accrued Liabilities, Net

 

(17,618,638)

 

 

(4,473,008)

 

 

Other Deferred Credits, Net

 

58,421,024

 

 

(18,393,279)

 

 

Total

$

25,793,558

 

$

(88,427,178)

 

(b) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -6795311
(c) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: -5995975
(d) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -15771388
(e) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -1448850545
(f) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -20024063
(g) Concept: OtherConstructionAndAcquisitionOfPlantInvestmentActivities
Original value: -1420461
(h) Concept: CashOutflowsForPlant
Original value: -1430246943
(i) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -30007870
(j) Concept: NetIncreaseDecreaseInReceivablesOperatingActivities
Original value: -13367621
(k) Concept: NetIncreaseDecreaseInInventoryOperatingActivities
Original value: 3199496
(l) Concept: NetIncreaseDecreaseInOtherRegulatoryAssetsOperatingActivities
Original value: -100952044
(m) Concept: GrossAdditionsToUtilityPlantLessNuclearFuelInvestingActivities
Original value: -997704463
(n) Concept: GrossAdditionsToNonutilityPlantInvestingActivities
Original value: -17832
(o) Concept: AllowanceForOtherFundsUsedDuringConstructionInvestingActivities
Original value: -6839780
(p) Concept: CashOutflowsForPlant
Original value: -991709283
(q) Concept: PaymentsForRetirementOfLongTermDebtFinancingActivities
Original value: -100897525
(r) Concept: OtherRetirementsOfBalancesImpactingCashFlowsFromFinancingActivities
Original value: -169504561

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.

INDEX OF NOTES TO FINANCIAL STATEMENTS

 

 

Glossary of Terms for Notes

1.

Organization and Summary of Significant Accounting Policies

2.

New Accounting Pronouncements

3.

Comprehensive Income

4.

Rate Matters

5.

Effects of Regulation

6.

Commitments, Guarantees and Contingencies

7.

Benefit Plans

8.

Business Segments

9.

Derivatives and Hedging

10.

Fair Value Measurements

11.

Income Taxes

12.

Leases

13.

Financing Activities

14.

Related Party Transactions

15.

Property, Plant and Equipment

16.

Revenue from Contracts with Customers

 


GLOSSARY OF TERMS FOR NOTES

 

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term

 

Meaning

 

 

 

AEP

 

American Electric Power Company, Inc., an investor-owned electric public utility holding company which includes American Electric Power Company, Inc. (Parent) and majority owned subsidiaries and affiliates.

AEP System

 

American Electric Power System, an electric system, owned and operated by AEP subsidiaries.

AEP Texas

 

AEP Texas Inc., an AEP electric utility subsidiary.

AEP Utilities

 

AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSW Energy, Inc.  Effective December 31, 2016, TCC and TNC were merged into AEP Utilities, Inc.  Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. were transferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP Texas Inc.

AEPEP

 

AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading, hedging activities, asset management and commercial and industrial sales in the deregulated Ohio and Texas markets.

AEPSC

 

American Electric Power Service Corporation, an AEP service subsidiary providing management and professional services to AEP and its subsidiaries.

AFUDC

 

Allowance for Funds Used During Construction.

AOCI

 

Accumulated Other Comprehensive Income.

ARAM

 

Average Rate Assumption Method, an IRS approved method used to calculate the reversal of Excess ADIT for ratemaking purposes.

ARO

 

Asset Retirement Obligations.

ASU

 

Accounting Standards Update.

CWIP

 

Construction Work in Progress.

EIS

 

Energy Insurance Services, Inc., a nonaffiliated captive insurance company.

ERCOT

 

Electric Reliability Council of Texas regional transmission organization.

ETT

 

Electric Transmission Texas, LLC, an equity interest joint venture between AEP Transmission Holdco and Berkshire Hathaway Energy Company formed to own and operate electric transmission facilities in ERCOT.

Excess ADIT

 

Excess accumulated deferred income taxes.

FASB

 

Financial Accounting Standards Board.

Federal EPA

 

United States Environmental Protection Agency.

FERC

 

Federal Energy Regulatory Commission.

FTR

 

Financial Transmission Right, a financial instrument that entitles the holder to receive compensation for certain congestion-related transmission charges that arise when the power grid is congested resulting in differences in locational prices.

GAAP

 

Accounting Principles Generally Accepted in the United States of America.

IRS

 

Internal Revenue Service.

MTM

 

Mark-to-Market.

MW

 

Megawatt.

OATT

 

Open Access Transmission Tariff.

Oklaunion Power Station

 

A single unit coal-fired generation plant totaling 650 MW located in Vernon, Texas. The plant is jointly owned by AEP Texas, PSO and certain nonaffiliated entities.

OPEB

 

Other Postretirement Benefits.

OTC

 

Over the counter.

Parent

 

American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP consolidation.

PPA

 

Purchase Power and Sale Agreement.

PSO

 

Public Service Company of Oklahoma, an AEP electric utility subsidiary.

PUCT

 

Public Utility Commission of Texas.

REP

 

Texas Retail Electric Provider.

Risk Management Contracts

 

Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.

SEC

 

U.S. Securities and Exchange Commission.

Tax Reform

 

On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal Revenue Code of 1986, including a reduction in the corporate federal income tax rate from 35% to 21% effective January 1, 2018.

TCC

 

Formerly AEP Texas Central Company, now a division of AEP Texas.

Texas Restructuring Legislation

 

Legislation enacted in 1999 to restructure the electric utility industry in Texas.

TNC

 

Formerly AEP Texas North Company, now a division of AEP Texas.

Utility Money Pool

 

Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain utility subsidiaries.


1.  ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

ORGANIZATION

 

AEP Texas was formed by the merger of TCC and TNC into AEP Utilities, Inc. on December 31, 2016. The merging parties retained their respective rate structures. Following the merger, AEP Utilities, Inc. changed its name to AEP Texas Inc.

 

AEP Texas is engaged in the transmission and distribution of electric power to approximately 1,050,000 retail customers through REPs in west, central and southern Texas. Among the principal industries served by AEP Texas are petroleum and coal products manufacturing, chemical manufacturing, oil and gas extraction, pipeline transportation and primary metal manufacturing. The territory served by AEP Texas also includes several military installations and correctional facilities.  AEP Texas is a member of ERCOT.  Under Texas Restructuring Legislation, AEP Texas’ utility predecessors, TCC and TNC, exited the generation business and ceased serving retail load. However, AEP Texas continues as part owner in the Oklaunion Power Station operated by PSO, which management announced plans to close by October 2020 pending necessary approvals.

 

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Rates and Service Regulation

 

AEP Texas’ rates are regulated by the FERC and PUCT.  The FERC also regulates AEP Texas’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act.  The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company.  For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate.  The PUCT also regulates certain intercompany transactions under various orders and affiliate statutes.  Both the FERC and PUCT are permitted to review and audit the relevant books and records of companies within a public utility holding company system.

 

The PUCT regulates all of the retail distribution operations and rates of AEP Texas’ retail public utility subsidiaries on a cost basis.

 

The FERC also regulates AEP Texas’ wholesale transmission operations and rates.  Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the PUCT.

 

Basis of Accounting

 

AEP Texas’ accounting is subject to the requirements of the PUCT and the FERC. The financial statements have been prepared in accordance with the Uniform System of Accounts prescribed by the FERC. The principal differences from GAAP include:

·

Accounting for subsidiaries on an equity basis.

·

The requirement to report deferred tax assets and liabilities separately rather than as a single amount.

·

The classification of accrued taxes as a single amount rather than as assets and liabilities.

·

The exclusion of current maturities of long-term debt from current liabilities.

·

The classification of accrued non-ARO asset removal costs as accumulated depreciation rather than regulatory liabilities.

·

The classification of capital lease payments as operating activities instead of financing activities.

·

The classification of gains/losses from disposition of allowances as utility operating expenses rather than as operating revenues.

·

The classification of tax assets related to the accounting guidance for “Uncertainty in Income Taxes” as a reduction to current liabilities rather than a tax benefit.

·

The classification of noncurrent tax liabilities related to the accounting guidance for “Uncertainty in Income Taxes” as a current liability rather than a noncurrent liability.

·

The classification of an accrued provision for potential refund as other noncurrent liability rather than a current liability.

·

The classification of regulatory assets and liabilities related to the accounting guidance for “Accounting for Income Taxes” as separate assets and liabilities rather than as a single amount.

·

The presentation of capital leased assets and their associated accumulated amortization as a single amount instead of as separate amounts.

·

The classification of certain nonoperating revenues as miscellaneous nonoperating income instead of as operating revenue.

·

The classification of certain nonoperating expenses as miscellaneous nonoperating expense instead of as operating expense.

·

The separate classification of income tax expense for operating and nonoperating activities instead of as a single income tax expense.

·

The classification of interest receivable and interest accrued related to federal income tax and state income tax balances as separate current assets and current liabilities rather than as a single net amount.

·

The classification of unamortized loss on reacquired debt in deferred debits rather than in regulatory assets.

·

The classification of accumulated deferred investment tax credits in deferred credits rather than in regulatory liabilities and deferred investment tax credits.

·

The accounting for AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC as nonaffiliated companies rather than consolidating the entities in accordance with the accounting guidance for "Variable Interest Entities."

·

The classification of deferred equity income in other deferred credits rather than in other non-current assets as securitized transition assets.

·

The classification of amortization of deferred equity in operating revenues rather than in depreciation and amortization.

·

The classification of certain other assets and liabilities as current instead of noncurrent.

·

The classification of certain other assets and liabilities as noncurrent instead of current.

·

The classification of debt issuance costs as noncurrent assets instead of noncurrent liabilities.

·

The classification of rents receivable as rents receivable instead of customer accounts receivable.

·

The classification of Non-Service Cost Components of Net Periodic Benefit Cost as Operating Expense instead of Other Income (Expense).

 

Accounting for the Effects of Cost-Based Regulation

 

AEP Texas’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated.  In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.

 

Use of Estimates

 

The preparation of these financial statements requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes.  These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits.  The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements.  Actual results could ultimately differ from those estimates.

 

Cash and Cash Equivalents

 

Cash and Cash Equivalents include Cash, Working Fund and Temporary Cash Investments on the balance sheets with original maturities of three months or less.

 

Supplementary Information

 

2018

 

2017

For the Years Ended December 31,

(in millions)

 

Cash was Paid (Received) for:

 

 

 

 

 

 

 

Interest (Net of Capitalized Amounts)

$

106.9

 

$

86.1

 

 

Income Taxes (Net of Refunds)

 

7.9

 

 

(28.1

)

Noncash Acquisitions Under Capital Leases

 

10.6

 

 

8.2

 

As of December 31,

 

 

 

 

 

 

Construction Expenditures Included in Current and Accrued Liabilities

 

243.1

 

 

325.7

 

 

Special Deposits

 

Special Deposits include funds held by trustees primarily for margin deposits for risk management activities.

 

Inventory

 

Fossil fuel and materials and supplies inventories are carried at average cost.

 

Accounts Receivable

 

Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities.

 

Revenue is recognized over time as the performance obligations of delivering energy to customers are satisfied.  To the extent that deliveries have occurred but a bill has not been issued, AEP Texas accrues and recognizes, as Accrued Utility Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing.

 

Allowance for Uncollectible Accounts

 

For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified.  Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.

 

Concentrations of Credit Risk and Significant Customers

 

AEP Texas had significant transactions with REPs which on a combined basis account for the following percentages of Operating Revenues for the years ended December 31 and Customer Accounts Receivable as of December 31:

Significant Customers of AEP Texas:

 

 

 

 

Centrica, Just Energy, TXU Energy and Reliant Energy

 

2018 (a)

 

2017

Percentage of Operating Revenues

 

54

%

 

66

%

Percentage of Customer Accounts Receivable

 

36

%

 

50

%

 

  1. Just Energy did not meet the Operating Revenue threshold of 10% in order to be considered a significant customer.

 

AEP Texas monitors credit levels and the financial condition of its customers on a continuous basis to minimize credit risk.  The PUCT allows recovery in rates for a reasonable level of bad debt costs.  Management believes adequate provisions for credit loss have been made in the accompanying financial statements.

 

Property, Plant and Equipment

 

Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts.  Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation.  The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss.  The equipment in each primary electric plant account is identified as a separate group.  The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received.  These rates and the related lives are subject to periodic review.   Removal costs accrued are charged to accumulated depreciation. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses.

 

Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.”  When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed or is not probable, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale.  Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available.  In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.

 


Investment in Subsidiary Company

 

AEP Texas has a wholly-owned subsidiary, AEP Texas North Generation Company, LLC. AEP Texas transferred all of its mothballed generation assets and related liabilities to this subsidiary, substantially completing the business separation requirement of the Texas Restructuring Legislation.

 

AEP Texas also has three wholly-owned subsidiaries, AEP Texas Central Transition Funding I LLC, AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC, that are engaged in financing activities associated with AEP Texas’s securitized transition assets. Investments in the net assets of AEP Texas’s three wholly-owned subsidiaries are carried at cost plus equity in their undistributed earnings since creation.

 

Allowance for Funds Used During Construction

 

AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant.

 

Valuation of Nonderivative Financial Instruments

 

The book values of Cash, Special Deposits, Working Fund, Notes Receivable from Associated Companies, Notes Payable to Associated Companies, accounts receivable and accounts payable approximate fair value because of the short-term maturity of these instruments.

 

Fair Value Measurements of Assets and Liabilities

 

The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value.  The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value.  Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability.

 

For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1.  Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1.  Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated.  Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace.  When multiple broker quotes are obtained, the quoted bid and ask prices are averaged.  In certain circumstances, a broker quote may be discarded if it is a clear outlier.  Management uses a historical correlation analysis between the broker quoted location and the illiquid locations.  If the points are highly correlated, these locations are included within Level 2 as well.  Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information.  Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs.  Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3.  The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market.  A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility.

 

AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan.  AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value.  AEP’s management performs its own valuation testing to verify the fair values of the securities.  AEP receives audit reports of the trustee’s operating controls and valuation processes.  The trustee uses multiple pricing vendors for the assets held in the trusts.

 

Assets in the benefits trusts are classified using the following methods.  Equities are classified as Level 1 holdings if they are actively traded on exchanges.  Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and equity securities.  They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets.  Items classified as Level 2 are primarily investments in individual fixed income securities.  Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data.  Pricing vendors calculate bond valuations using financial models and matrices.  The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation.  Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments.  Investments with unobservable valuation inputs are classified as Level 3 investments.  Investments classified as Other are valued using Net Asset Value as a practical expedient. Items classified as Other are primarily cash equivalent funds, common collective trusts, commingled funds, structured products, private equity, real estate, infrastructure and alternative credit investments. These investments do not have a readily determinable fair value or they contain redemption restrictions which may include the right to suspend redemptions under certain circumstances. Redemption restrictions may also prevent certain investments from being redeemed at the reporting date for the underlying value.

 

Revenue Recognition

 

Regulatory Accounting

 

AEP Texas’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated.  Regulatory assets (deferred expenses or alternative revenues recognized in accordance with the guidance for “Regulated Operations”) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching revenue with its passage to customers in cost-based regulated rates.

 

When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets.  Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur.  Examples of new events include the issuance of a regulatory commission order or passage of new legislation.  If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is derecognized as a charge against income.

 

Retail and Wholesale Supply and Delivery of Electricity

 

AEP Texas recognizes revenues from customers for retail and wholesale electricity sales and electricity transmission and distribution delivery services.  AEP Texas recognizes such revenues on the statements of income as the performance obligations of delivering energy to customers are satisfied. Recognized revenues include both billed and unbilled amounts. 

 

Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. Revenues initially recognized per the annual rate filing are compared to actual costs, resulting in the subsequent recognition of an over or under recovered amount, with interest, that is refunded or recovered, respectively, in a future year’s rates. These annual true-ups meet the definition of alternative revenues in accordance with the accounting guidance for “Regulated Operations”, and are recognized by AEP Texas in the second quarter following the filing of annual FERC reports. Any portion of the true-ups applicable to an affiliated company is recorded as Accounts Receivable from Associated Companies or Accounts Payable to Associated Companies on the balance sheets. Any portion of the true-ups applicable to third parties is recorded as regulatory assets or regulatory liabilities on the balance sheets. See Note 16 - Revenue from Contracts with Customers for additional information related to retail and wholesale revenues.

 

Power Purchase and Sale Agreement

 

AEP Texas recognizes revenue from an affiliate, AEPEP, for a 20-year PPA. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes on a billed basis. Revenue is recognized for the capacity and depreciation billed to AEPEP on a straight-line basis over the term of the PPA as these amounts represent the minimum amount due.

 

Maintenance

 

AEP Texas expenses maintenance costs as incurred.  If it becomes probable that AEP Texas will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with its recovery in cost-based regulated revenues.

 

Income Taxes and Investment Tax Credits (ITC)

 

AEP Texas uses the liability method of accounting for income taxes.  Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which the temporary differences are expected to be recovered or settled. AEP Texas revalued deferred tax assets and liabilities at the new federal corporate income tax rate of 21% in December 2017. See Note 11 - Income Taxes for additional information related to Tax Reform.

 

When the flow-through method of accounting for temporary differences is required by a regulator to be reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense.

 

AEP Texas applies the deferral methodology for the recognition of ITC. Deferred ITC is amortized to income tax expense over the life of the asset that generated the credit. Amortization of deferred ITC begins when the asset is placed into service, except where regulatory commissions reflect ITC in the rate-making process, then amortization begins when the cash tax benefit is recognized.

 

AEP Texas accounts for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.”  AEP Texas classifies interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classifies penalties as Penalties on the statements of income.

 

Excise Taxes

 

As an agent for some state and local governments, AEP Texas collects from customers certain excise taxes levied by those state or local governments on customers.  AEP Texas does not record these taxes as revenue or expense.

 

Debt

 

Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced.  If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates.

 

 

Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt.  The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations.

 

Pension and OPEB Plans

 

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all of AEP Texas’ employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP Texas also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. AEP Texas is allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. See Note 7 - Benefit Plans for additional information including significant accounting policies associated with the plans.

 

Investments Held in Trust for Future Liabilities

 

AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits.  All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations.  The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities.  To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers.  Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate.  Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities.  The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance.

 

Benefit Plans

 

All benefit plan assets are invested in accordance with each plan’s investment policy.  The investment policy outlines the investment objectives, strategies and target asset allocations by plan.

 

The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns.  Strategies used include:

 

  • Maintaining a long-term investment horizon.

  • Diversifying assets to help control volatility of returns at acceptable levels.

  • Managing fees, transaction costs and tax liabilities to maximize investment earnings.

  • Using active management of investments where appropriate risk/return opportunities exist.

  • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks.

  • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification.

 

The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities.  The current target asset allocations are as follows:

Pension Plan Assets

 

Target

Equity

 

25

%

Fixed Income

 

59

%

Other Investments

 

15

%

Cash and Cash Equivalents

 

1

%

 

 

 

OPEB Plans Assets

 

Target

Equity

 

49

%

Fixed Income

 

49

%

Cash and Cash Equivalents

 

2

%

 

The investment policy for each benefit plan contains various investment limitations.  The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies).  However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law.

 

For equity investments, the concentration limits are as follows:

 

  • No security in excess of 5% of all equities.

  • Cash equivalents must be less than 10% of an investment manager’s equity portfolio.

  • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio.

  • No investment in excess of 5% of an outstanding class of any company.

  • No securities may be bought or sold on margin or other use of leverage.

 

For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices.

 

A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation.  Real estate properties are illiquid, difficult to value and not actively traded.  The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties.  To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification.  Real estate holdings include core, value-added and opportunistic classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities.

 

A portion of the pension assets is invested in private equity.  Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance.  Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded.  The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum.   The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise.  The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments.

 

AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses.  AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral.  All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested.  The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security.  The securities lending program’s objective is to provide modest incremental income with a limited increase in risk. As of December 31, 2018 and 2017, the fair value of securities on loan as part of the program was $241 million and $492 million, respectively. Cash and securities obtained as collateral exceeded the fair value of the securities loaned as of December 31, 2018 and 2017.

 

Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts.  The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust.  Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid.  Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities.  With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds.  A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges.  The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities.

 

Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal.  The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities.  The cash funds are valued each business day and provide daily liquidity.

 

Comprehensive Income (Loss)

 

Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources.  It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners.

 

Subsequent Events

 

Management has evaluated the impact of events occurring after December 31, 2018 through February 21, 2019, the date that AEP Texas’ Form 10-K was issued, and has updated such evaluation for disclosure purposes through April 11, 2019. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.


2.
NEW ACCOUNTING PRONOUNCEMENTS

 

During FASB’s standard-setting process and upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to AEP Texas’ business. The following pronouncements will impact the financial statements.

 

ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09)

 

In May 2014, the FASB issued ASU 2014-09 changing the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract with a customer, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers.

 

Management adopted ASU 2014-09 effective January 1, 2018. The adoption of ASU 2014-09 did not have a material impact on results of operations, financial position or cash flows. In that regard, the application of the new standard did not cause any significant differences in any individual financial statement line items had those line items been presented in accordance with the guidance that was in effect prior to the adoption of the new standard. Further, given the lack of material impact to the financial statements, the adoption of the new standard did not give rise to any material changes in AEP Texas’ previously established accounting policies for revenue. See Note 16 - Revenue from Contracts with Customers for additional disclosures required by the new standard.

 

ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01)

 

In January 2016, the FASB issued ASU 2016-01 revising the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. For equity investments that do not have a readily determinable fair value, entities are permitted to elect a practicality exception and measure the investment at cost, less impairment, plus or minus observable price changes. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheets or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets.

 

Management adopted ASU 2016-01 effective January 1, 2018, by means of a cumulative-effect adjustment to the balance sheet. The adoption of ASU 2016-01 resulted in no impact to the results of operations, financial position or cash flows.

 

ASU 2016-02 “Accounting for Leases” (ASU 2016-02)

 

In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheets and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard.

 

New leasing standard implementation activities included the identification of the lease population within the AEP System as well as the sampling of representative lease contracts to analyze accounting treatment under the new accounting guidance. Based upon the completed assessments, management also prepared a gap analysis to outline new disclosure compliance requirements.

 

Management adopted ASU 2016-02 effective January 1, 2019 by means of a cumulative-effect adjustment to the balance sheet. Management elected the following practical expedients upon adoption:

Practical Expedient

 

Description

Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package)

 

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

Lease and Non-lease Components (elect by class of underlying asset)

 

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

Short-term Lease (elect by class of underlying asset)

 

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

Existing and expired land easements not previously accounted for as leases

 

Elect optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840.

Cumulative-effect adjustment in the period of adoption

 

Elect the optional transition practical expedient to adopt the new lease requirements through a cumulative-effect adjustment on the balance sheet in the period of adoption.

 

Management concluded that the result of adoption would not materially change the volume of contracts that qualify as leases going forward. The adoption of the new standard did not materially impact results of operations or cash flows, but did have a material impact on the balance sheets. An impact of $80 million to AEP Texas’ balance sheet has been estimated for the first quarter of 2019.

 

ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13)

 

In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination.

 

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 and related implementation guidance effective January 1, 2020.

 

ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07)

 

In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented on the statements of income separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component is eligible for capitalization as applicable following labor. Management adopted ASU 2017-07 effective January 1, 2018

 

ASU 2017-12 “Derivatives and Hedging” (ASU 2017-12)

 

In August 2017, the FASB issued ASU 2017-12 amending the recognition and presentation requirements for hedge accounting activities. The objectives of the new standard are to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements and to reduce the complexity of applying hedge accounting. Among other things, ASU 2017-12: (a) expands the types of transactions eligible for hedge accounting, (b) eliminates the separate measurement and presentation of hedge ineffectiveness, (c) simplifies the requirements for assessments of hedge effectiveness, (d) provides companies more time to finalize hedge documentation and (e) enhances presentation and disclosure requirements.

 

Management early adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. The adoption of ASU 2017-12 resulted in no impact to results of operations, financial position or cash flows. The adoption of the new standard did not give rise to any material changes to AEP Texas’ previously established accounting policies for derivatives and hedging.

 

ASU 2018-02 “Reclassification of Certain Tax Effects from AOCI” (ASU 2018-02)

 

In February 2018, the FASB issued ASU 2018-02 allowing a reclassification from AOCI to Retained Earnings for stranded tax effects resulting from Tax Reform. The accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be adjusted for the effect of a change in tax law or rates with the effect included in income from continuing operations in the reporting period that includes the enactment date of the tax change. This guidance is applicable for the tax effects of items in AOCI that were originally recognized in Other Comprehensive Income. As a result and absent the new guidance in this ASU, the tax effects of items within AOCI would not reflect the newly enacted corporate tax rate.

 

Management adopted ASU 2018-02 effective January 1, 2018, electing to reclassify the effects of the change in the federal corporate tax rate due to Tax Reform from AOCI to Retained Earnings. The portion of the one-time reclassification to Retained Earnings was recorded to FERC Account 439, Adjustments to Retained Earnings. A request was made in November 2018 for use of Account 439 and in January 2019 the FERC approved the request. The adoption of the ASU and the use of Account 439 had an insignificant effect on the Company’s rates charged to customers. Additionally, a portion of the reclassification was recorded to Other Regulatory Liabilities to adjust the tax effects of certain interest rate hedges that were previously deferred as a part of the accounting for Tax Reform. There were no other effects from Tax Reform that impacted AOCI. Management applied the new guidance at the beginning of the period of adoption. The adoption of the new standard did not have a material impact on the statement of financial position and did not impact results of operations or cash flows.

 

ASU 2018-14 “Disclosure Framework: Changes to the Disclosure Requirements for Defined Benefit Plans” (ASU 2018-14)

 

In August 2018, the FASB issued ASU 2018-14 modifying the disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendments remove disclosures that no longer are considered cost beneficial, clarify the specific requirements of disclosures and add disclosure requirements identified as relevant.

 

Management early adopted ASU 2018-14 for the 2018 Annual Report and applied the new standard retrospectively for all periods presented. As a result of adoption, AEP Texas’ disclosures were updated as follows:

 

  • Amended the disclosure to remove the amounts in AOCI expected to be recognized as components of net periodic benefit cost over the next fiscal year.

  • Amended the disclosure to remove the effects of a one-percentage-point change in assumed health care cost trend rates on the (a) aggregate of the service and interest cost components of net periodic benefit costs and (b) benefit obligation for postretirement health care benefits.

  • Amended the disclosure to include the weighted-average interest crediting rates for cash balance plans and other plans with promised interest crediting rates.

  • Amended the disclosure to include an explanation of the reasons for significant gains and losses related to changes in the benefit obligation for the period.

 

See Note 7 - Benefit Plans for updates to the disclosures required by the new standard.

 

ASU 2018-15 “Internal-Use Software: Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract” (ASU 2018-15)

 

In August 2018, the FASB issued ASU 2018-15 aligning the requirements for capitalizing implementation costs incurred in a cloud computing arrangement (hosting arrangement) that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The new standard requires an entity (customer) in a hosting arrangement that is a service contract to follow the accounting guidance for “Internal-Use Software” to determine which implementation costs to capitalize as an asset related to the service contract and which costs to expense. To eliminate diversity in practice, the new standard changes the presentation of implementation costs for cloud service arrangements that are service contracts without the purchase of a license. Implementation costs for cloud service contracts will be presented on the balance sheets in the same manner as a prepayment.   AEP Texas currently presents implementation costs in utility plant on the balance sheets. Under the new standard, amortization of capitalized implementation costs of a hosting arrangement will be recorded in Operation Expenses and Maintenance Expenses over the term of the cloud service arrangement, rather than Depreciation Expense on the statements of income.  Payments for capitalized implementation costs in the statement of cash flows will be classified in the same manner as payments made for fees associated with the hosting element.

 

The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019, with early adoption permitted. Management is analyzing the impact of this new standard and at this time, cannot estimate the impact of adoption on results of operations, financial position or cash flows. Management plans to adopt ASU 2018-15 prospectively, effective January 1, 2020.

 

3.  COMPREHENSIVE INCOME

 

Presentation of Comprehensive Income

 

The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2018 and 2017.  The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 - Benefit Plans for additional details.


Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and OPEB

 

 

 

 

 

 

Amortization

 

Changes in

 

 

 

 

Cash Flow Hedge –

 

of Deferred

 

Funded

 

 

 

 

Interest Rate

 

Costs

 

Status

 

Total

 

 

(in millions)

Balance in AOCI as of December 31, 2017

 

$

(4.5

)

 

$

4.5

 

 

$

(12.6

)

 

$

(12.6

)

Change in Fair Value Recognized in AOCI

 

 

 

 

 

(1.0

)

 

(1.0

)

Amount of (Gain) Loss Reclassified from AOCI

 

 

 

 

 

 

 

 

Interest on Long-Term Debt (a)

 

1.3

 

 

 

 

 

 

1.3

 

Amortization of Prior Service Cost (Credit)

 

 

 

(0.1

)

 

 

 

(0.1

)

Amortization of Actuarial (Gains) Losses

 

 

 

0.4

 

 

 

 

0.4

 

Reclassifications from AOCI, before Income Tax (Expense) Benefit

 

1.3

 

 

0.3

 

 

 

 

1.6

 

Income Tax (Expense) Benefit

 

0.3

 

 

0.1

 

 

 

 

0.4

 

Reclassifications from AOCI, Net of Income Tax (Expense) Benefit

 

1.0

 

 

0.2

 

 

 

 

1.2

 

Net Current Period Other Comprehensive Income (Loss)

 

1.0

 

 

0.2

 

 

(1.0

)

 

0.2

 

ASU 2018-02 Adoption (b)

 

(0.9

)

 

 

 

(1.8

)

 

(2.7

)

Balance in AOCI as of December 31, 2018

 

$

(4.4

)

 

$

4.7

 

 

$

(15.4

)

 

$

(15.1

)

 


Changes in Accumulated Other Comprehensive Income (Loss) by Component

For the Year Ended December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

Pension and OPEB

 

 

 

 

 

 

Amortization

 

Changes in

 

 

 

 

Cash Flow Hedge –

 

of Deferred

 

Funded

 

 

 

 

Interest Rate

 

Costs

 

Status

 

Total

 

 

(in millions)

Balance in AOCI as of December 31, 2016

 

$

(5.4

)

 

$

4.2

 

 

$

(13.7

)

 

$

(14.9

)

Change in Fair Value Recognized in AOCI

 

 

 

 

 

1.1

 

 

1.1

 

Amount of (Gain) Loss Reclassified from AOCI

 

 

 

 

 

 

 

 

Interest on Long-Term Debt (a)

 

1.3

 

 

 

 

 

 

1.3

 

Amortization of Prior Service Cost (Credit)

 

 

 

(0.1

)

 

 

 

(0.1

)

Amortization of Actuarial (Gains) Losses

 

 

 

0.5

 

 

 

 

0.5

 

Reclassifications from AOCI, before Income Tax (Expense) Benefit

 

1.3

 

 

0.4

 

 

 

 

1.7

 

Income Tax (Expense) Benefit

 

0.4

 

 

0.1

 

 

 

 

0.5

 

Reclassifications from AOCI, Net of Income Tax (Expense) Benefit

 

0.9

 

 

0.3

 

 

 

 

1.2

 

Net Current Period Other Comprehensive Income (Loss)

 

0.9

 

 

0.3

 

 

1.1

 

 

2.3

 

Balance in AOCI as of December 31, 2017

 

$

(4.5

)

 

$

4.5

 

 

$

(12.6

)

 

$

(12.6

)

 

(a) Amounts reclassified to the referenced line item on the statements of income.

(b) See Note 2 - New Accounting Pronouncements for additional information.


4.  RATE MATTERS

 

AEP Texas is involved in rate and regulatory proceedings at the FERC and the PUCT.  Rate matters can have a material impact on net income, cash flows and possibly financial condition.  AEP Texas’ recent significant rate orders and pending rate filings are addressed in this note.

 

Impact of Tax Reform

 

Rate and regulatory matters are impacted by federal income tax implications. In December 2017, Tax Reform was enacted, which impacts outstanding rate and regulatory matters. For additional details on the impact of Tax Reform, see Note 11 - Income Taxes.

 

AEP Texas Interim Transmission and Distribution Rates

 

As of December 31, 2018, AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2018, subject to review, are estimated to be $1 billion. A base rate review could result in a refund to customers if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition.

 

In April 2018, the PUCT adopted a rule requiring investor-owned utilities operating solely within ERCOT to make periodic filings for rate proceedings. The rule requires AEP Texas to file for a comprehensive rate review no later than May 1, 2019.

 

In 2018, the PUCT issued approvals to increase AEP Texas’ transmission rates by $22 million annually. The approvals included an increase in annual revenues to recover transmission capital additions of $46 million offset by a reduction in annual revenues of $24 million due to the reduction in the federal income tax rate due to Tax Reform. The approvals did not address the return of Excess ADIT benefits to customers.

 

In August 2018, the PUCT approved a Stipulation and Settlement agreement to amend AEP Texas’ Distribution Cost Recovery Factor to reduce annual distribution rates by approximately $24 million annually, beginning September 1, 2018. The settlement included an increase in annual revenues to recover 2017 distribution capital additions of $19 million offset by reductions in annual revenues of: (a) $21 million due to the reduction in the federal income tax rate due to Tax Reform, (b) $10 million due to Excess ADIT associated with certain depreciable property to be amortized using ARAM and (c) $12 million due to Excess ADIT that is not subject to rate normalization requirements to be refunded over 5 years.

 

Hurricane Harvey and Texas Storm Cost Securitization

 

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. AEP Texas has a PUCT approved catastrophe reserve in base rates and can defer incremental storm expenses. AEP Texas currently recovers approximately $1 million of storm costs annually through base rates. As of December 31, 2018, the total balance of AEP Texas’ regulatory asset for deferred storm costs is approximately $152 million, inclusive of approximately $129 million of incremental storm expenses related to Hurricane Harvey. See the table below for additional information on the Hurricane Harvey storm restoration costs:


 

 

December 31, 2018

Total Hurricane Harvey Storm Costs

 

Capital

 

O&M

 

Regulatory Asset

 

Total

 

 

(in millions)

Restoration Costs Incurred

 

$

219.1

 

 

$

136.9

 

 

$

 

 

$

356.0

 

Incremental Operation and Maintenance Expenses (O&M)

 

 

 

(129.8

)

 

129.8

 

 

 

Insurance Proceeds

 

(12.7

)

 

 

 

(1.2

)

 

(13.9

)

Total Hurricane Harvey Storm Costs, Net

 

$

206.4

 

 

$

7.1

 

 

$

128.6

 

 

$

342.1

 

 

The securitization of storm cost recovery in Texas requires two filings with the PUCT. In August 2018, AEP Texas filed a Determination of System Restoration Costs (DSRC) with the PUCT for total estimated storm costs in the amount of $425 million, which includes estimated carrying costs. The total estimated storm costs net of insurance proceeds, tax credits received for the Disaster Tax Relief and Airport and Airway Extension Act of 2017, and Excess ADIT that is not subject to rate normalization requirements utilized to reduce the non-capital Hurricane Harvey costs is $370 million.

 

In November 2018, AEP Texas, the PUCT staff and intervenors filed a stipulation and settlement agreement with the PUCT that included all aspects of the DSRC filing with the following exceptions: (a) a $5 million permanent storm restoration reduction, (b) a $4 million disallowance of charges not directly related to storm restoration that will be included in a future regulatory proceeding and (c) a $5 million disallowance due to additional insurance proceeds received. See the table below for a reconciliation of the filed Determination of System Restoration Costs and settlement and stipulation agreement:

Total Estimated Storm Costs Requested in the DSRC

 

December 31, 2018

 

 

(in millions)

Total Estimated Hurricane Harvey Storm Costs

 

$

356.0

 

Estimated Hurricane Harvey Carrying Costs

 

31.5

 

Estimated Litigation Costs

 

0.6

 

Non-Hurricane Harvey Storm Restoration Costs

 

36.5

 

Total Estimated Storm Costs requested in the DSRC

 

424.6

 

less:

 

 

Tax Credit

 

(0.8

)

Insurance Proceeds

 

(8.7

)

Excess ADIT (a)

 

(45.5

)

Total Estimated Storm Costs requested in the DSRC, after adjustments

 

369.6

 

less:

 

 

Settlement Agreement Adjustments

 

(10.6

)

Incremental Insurance Proceeds Received

 

(5.1

)

Total Estimated Storm Costs per Settlement Agreement

 

$

353.9

 

 

  1. Amount represents Non-Hurricane Harvey Excess ADIT that is not subject to rate normalization requirements.

 

AEP Texas will seek to securitize estimated distribution related assets of $247 million in the first half of 2019 while the remaining $107 million of estimated transmission related assets is expected to be recovered through interim transmission filings or an upcoming base rate case. If these costs are not recovered, it could have an adverse effect on future net income, cash flows and financial condition.


5.  
EFFECTS OF REGULATION

 

Regulatory assets and liabilities are comprised of the following items:

 

 

December 31,

 

Remaining

Recovery

Period

Regulatory Assets:

 

2018

 

2017

 

 

 

 

(in millions)

 

 

Regulatory assets pending final regulatory approval:

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets Currently Not Earning a Return

 

 

 

 

 

 

Storm-Related Costs (a)

 

$

152.4

 

 

$

123.3

 

 

 

Rate Case Expense

 

0.2

 

 

0.1

 

 

 

Total Regulatory Assets Pending Final Regulatory Approval

 

152.6

 

 

123.4

 

 

 

 

 

 

 

 

 

 

Regulatory assets approved for recovery:

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Assets Currently Earning a Return

 

 

 

 

 

 

Advanced Metering System

 

45.3

 

 

33.5

 

 

2 years

Meter Replacement Costs

 

40.1

 

 

44.9

 

 

9 years

Total Regulatory Assets Currently Earning a Return

 

85.4

 

 

78.4

 

 

 

Regulatory Assets Currently Not Earning a Return

 

 

 

 

 

 

Pension and OPEB Funded Status

 

176.9

 

 

151.2

 

 

12 years

Income Tax Assets Subject to Flow Through

 

45.8

 

 

41.9

 

 

31 years

Securitization Assets

 

12.3

 

 

21.7

 

 

2 years

Transmission Cost Recovery Factor

 

1.7

 

 

9.5

 

 

2 years

Other Regulatory Assets Approved for Recovery

 

7.4

 

 

8.6

 

 

various

Total Regulatory Assets Currently Not Earning a Return

 

244.1

 

 

232.9

 

 

 

 

 

 

 

 

 

 

 

 

Total Regulatory Assets Approved for Recovery

 

329.5

 

 

311.3

 

 

 

 

 

 

 

 

 

 

Total FERC Account 182.3 Regulatory Assets

 

$

482.1

 

 

$

434.7

 

 

 

 

  1. As of December 31, 2018, AEP Texas has deferred $129 million related to Hurricane Harvey and will seek securitization of the distribution related assets. See Note 4 - Rate Matters for additional information.


 

 

December 31,

 

Remaining

Refund

Period

Regulatory Liabilities:

 

2018

 

2017

 

 

 

 

(in millions)

 

 

Regulatory liabilities pending final regulatory determination:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income Tax Related Regulatory Liabilities (a)

 

 

 

 

 

 

Excess ADIT Associated with Certain Depreciable Property

 

$

277.1

 

 

$

578.3

 

 

 

Excess ADIT that is Not Subject to Rate Normalization Requirements

 

141.5

 

 

103.3

 

 

 

Total Regulatory Liabilities Pending Final Regulatory Determination

 

418.6

 

 

681.6

 

 

 

 

 

 

 

 

 

 

Regulatory liabilities approved for payment:

 

 

 

 

 

 

 

 

 

 

 

 

 

Regulatory Liabilities Currently Paying a Return

 

 

 

 

 

 

Advanced Metering Infrastructure Surcharge

 

8.5

 

 

12.7

 

 

2 years

Excess Earnings

 

6.3

 

 

6.8

 

 

13 years

Total Regulatory Liabilities Currently Paying a Return

 

14.8

 

19.5

 

 

Regulatory Liabilities Currently Not Paying a Return

 

 

 

 

 

 

Other Regulatory Liabilities Approved for Payment

 

 

 

0.6

 

 

various

Total Regulatory Liabilities Currently Not Paying a Return

 

 

 

0.6

 

 

 

Income Tax Related Regulatory Liabilities (a)

 

 

 

 

 

 

 

 

Excess ADIT Associated with Certain Depreciable Property

 

251.9

 

 

 

 

(b)

Income Tax Liabilities Subject to Flow Through

 

2.9

 

 

3.2

 

 

31 years

Total Income Tax Related Regulatory Liabilities

 

254.8

 

 

3.2

 

 

 

 

 

 

 

 

 

 

 

 

Total Regulatory Liabilities Approved for Payment

 

269.6

 

 

23.3

 

 

 

 

 

 

 

 

 

 

Total FERC Account 254 Regulatory Liabilities

 

$

688.2

 

 

$

704.9

 

 

 

 

  1. This balance primarily represents regulatory liabilities for Excess ADIT as a result of the reduction in the corporate federal income tax rate from 35% to 21% related to the enactment of Tax Reform.  The regulatory liability balance predominately pays a return due to the inclusion of Excess ADIT in rate base.  See “Federal Tax Reform and Legislation” section of Note 11 - Income Taxes for additional information.

  2. Refunded using ARAM.

 


6.  COMMITMENTS, GUARANTEES AND CONTINGENCIES

 

AEP Texas is subject to certain claims and legal actions arising in the ordinary course of business.  In addition, AEP Texas’ business activities are subject to extensive governmental regulation related to public health and the environment.  The ultimate outcome of such pending or potential litigation cannot be predicted.  Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates.

 

For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements.

 

GUARANTEES

 

Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.”  There is no collateral held in relation to any guarantees.  In the event any guarantee is drawn, there is no recourse to third-parties unless specified below.

 

Letters of Credit

 

Standby letters of credit are entered into with third-parties.  These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

 

An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP issues letters of credit on behalf of AEP Texas under four uncommitted facilities totaling $305 million. AEP Texas’ maximum future payments for letters of credit issued under the uncommitted facilities as of December 31, 2018 was $3 million with a maturity date of January 2019. In January 2019, the letter of credit was amended to $2 million and the maturity date was extended until January 2020.

 

Indemnifications and Other Guarantees

 

Contracts

 

AEP Texas enters into certain types of contracts which require indemnifications.  Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements.  Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters.  With respect to sale agreements, exposure generally does not exceed the sale price.  As of December 31, 2018, there were no material liabilities recorded for any indemnifications.

 

Lease Obligations

 

AEP Texas leases equipment under master lease agreements.  See “Master Lease Agreements” section of Note 12 - Leases for additional information.

 

 

 

 

 

ENVIRONMENTAL CONTINGENCIES

 

The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation

 

The transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and non-hazardous materials.  AEP Texas currently incurs costs to dispose of these substances safely.

 

Superfund addresses clean-up of hazardous substances that are released to the environment.  The Federal EPA administers the clean-up programs.  Several states enacted similar laws. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories.  Liability has been resolved for a number of sites with no significant effect on net income.

 

Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability.  Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often non-hazardous.  Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as Potentially Responsible Parties for each site and several of the parties are financially sound enterprises.  As of December 31, 2018, management’s estimates do not anticipate material clean-up costs for identified Superfund sites.

 

OPERATIONAL CONTINGENCIES

 

Insurance and Potential Losses

 

AEP Texas maintains insurance coverage normal and customary for electric utilities, subject to various deductibles.  AEP Texas also maintains property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions.  Covered property generally includes power plants, substations, facilities and inventories.  Excluded property generally includes transmission and distribution lines, poles and towers.  The insurance programs also generally provide coverage against loss arising from certain claims made by third-parties and are in excess of retentions absorbed by AEP Texas.  Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers.

 

Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident.  Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition.

 

7.  BENEFIT PLANS

 

For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1.

 

AEP Texas participates in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP Texas also participates in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

 

AEP Texas recognizes the funded status associated with defined benefit pension and OPEB plans on the balance sheets.  Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance.  AEP Texas recognizes an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognizes, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost.  AEP Texas records a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery.  The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

 

Actuarial Assumptions for Benefit Obligations

 

The weighted-average assumptions used in the measurement of benefit obligations are shown in the following table:

 

 

Pension Plans

 

 

OPEB

 

 

December 31,

Assumption

 

2018 

 

 

2017 

 

 

2018 

 

2017 

Discount Rate

 

4.30

%

 

 

3.65

%

 

 

4.30

%

 

3.60

%

Interest Crediting Rate

 

4.00

%

 

 

4.00

%

 

 

NA

 

NA

Rate of Compensation Increase

 

4.95

%

(a)

 

4.90

%

(a)

 

NA

 

NA

 

  1. Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

 

A duration-based method is used to determine the discount rate for the plans.  A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability.  The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan.

 

For 2018, the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above.

 

Actuarial Assumptions for Net Periodic Benefit Costs

 

The weighted-average assumptions used in the measurement of benefit costs are shown in the following table:

 

Pension Plans

 

OPEB

 

 

Years Ended December 31,

Assumption

 

2018

 

2017

 

2018

 

2017

Discount Rate

 

3.65

%

 

4.05

%

 

3.60

%

 

4.10

%

Interest Crediting Rate

 

4.00

%

 

4.00

%

 

NA

 

NA

Expected Return on Plan Assets

 

6.00

%

 

6.00

%

 

6.00

%

 

6.75

%

Rate of Compensation Increase

 

4.95

%

(a)

4.90

%

(a)

NA

 

NA

 

  1. Rates are for base pay only.  In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

NA Not applicable.

 

The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third-party forecasts and current prospects for economic growth.

 

The health care trend rate assumptions used for OPEB plans measurement purposes are shown below:

 

 

December 31,

Health Care Trend Rates

 

2018

 

2017

Initial

 

6.25

%

 

6.50

%

Ultimate

 

5.00

%

 

5.00

%

Year Ultimate Reached

 

2024

 

2024

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 


Significant Concentrations of Risk within Plan Assets

 

In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets.  The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits.  The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment.  Management monitors the plans to control security diversification and ensure compliance with the investment policy.  As of December 31, 2018, the assets were invested in compliance with all investment limits.  See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details.

 

Benefit Plan Obligations, Plan Assets, Funded Status and Amounts Recognized on the Balance Sheets

 

For the year ended December 31, 2018, the pension and OPEB plans had an actuarial gain due to an increase in the discount rate as well as updated estimates for future medical expenses in the OPEB plans. For the year ended December 31, 2017, the pension plans had an actuarial loss due to a decrease in the discount rate. The OPEB plans had an actuarial gain primarily due to a change in medical benefits for retirees which was partially offset by a decrease in the discount rate. The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets, funded status and the presentation on the balance sheets.  The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively.

 

 

Pension Plans

 

OPEB

 

 

2018

 

2017

 

2018

 

2017

Change in Benefit Obligation

 

(in millions)

Benefit Obligation as of January 1,

 

$

441.3

 

 

$

421.7

 

 

$

107.1

 

 

$

120.4

 

Service Cost

 

9.2

 

 

8.6

 

 

0.9

 

 

0.9

 

Interest Cost

 

16.0

 

 

17.1

 

 

3.8

 

 

4.9

 

Actuarial (Gain) Loss

 

(20.9

)

 

25.6

 

 

(8.3

)

 

(11.9

)

Benefit Payments

 

(36.3

)

 

(31.7

)

 

(10.7

)

 

(10.8

)

Participant Contributions

 

 

 

 

 

3.1

 

 

3.6

 

Benefit Obligation as of December 31,

 

$

409.3

 

 

$

441.3

 

 

$

95.9

 

 

$

107.1

 

 

 

 

 

 

 

 

 

 

Change in Fair Value of Plan Assets

 

 

 

 

 

 

 

 

Fair Value of Plan Assets as of January 1,

 

$

455.9

 

 

$

416.6

 

 

$

147.3

 

 

$

134.1

 

Actual Gain (Loss) on Plan Assets

 

(9.3

)

 

61.8

 

 

(14.6

)

 

20.4

 

Company Contributions

 

0.4

 

 

9.2

 

 

4.8

 

 

 

Participant Contributions

 

 

 

 

 

3.1

 

 

3.6

 

Benefit Payments

 

(36.3

)

 

(31.7

)

 

(10.7

)

 

(10.8

)

Fair Value of Plan Assets as of December 31,

 

$

410.7

 

 

$

455.9

 

 

$

129.9

 

 

$

147.3

 

 

 

 

 

 

 

 

 

 

Funded Status as of December 31,

 

$

1.4

 

 

$

14.6

 

 

$

34.0

 

 

$

40.2

 

 


 

 

Pension Plans

 

OPEB

 

 

December 31,

 

 

2018

 

2017

 

2018

 

2017

 

 

(in millions)

Special Funds – Prepaid Benefit Costs

 

$

5.2

 

 

$

18.6

 

 

$

34.0

 

 

$

40.2

 

Miscellaneous Current and Accrued Liabilities – Short-term Benefit Liability

 

(0.4

)

 

(0.4

)

 

 

 

 

Accumulated Provision for Pensions and Benefits – Long-term Benefit Liability

 

(3.4

)

 

(3.6

)

 

 

 

 

Funded Status

 

$

1.4

 

 

$

14.6

 

 

$

34.0

 

 

$

40.2

 

 


Amounts Included in Regulatory Assets, Deferred Income Taxes, AOCI and Income Tax Expense

 

The following tables show the components of the plans included in regulatory assets, Deferred Income Taxes, AOCI and Income Tax Expense and the items attributable to the change in these components:

 

 

Pension Plans

 

OPEB

 

 

December 31,

 

 

2018

 

2017

 

2018

 

2017

Components

 

(in millions)

Net Actuarial Loss

 

$

182.0

 

 

$

175.2

 

 

$

38.0

 

 

$

23.9

 

Prior Service Credit

 

 

 

 

 

(29.5

)

 

(35.4

)

 

 

 

 

 

 

 

 

 

Recorded as

 

 

 

 

 

 

 

 

Regulatory Assets

 

$

168.2

 

 

$

161.4

 

 

$

8.7

 

 

$

(10.2

)

Deferred Income Taxes

 

2.9

 

 

2.9

 

 

 

 

(0.3

)

Net of Tax AOCI

 

10.9

 

 

8.9

 

 

(0.2

)

 

(0.8

)

Income Tax Expense (a)

 

 

 

2.0

 

 

 

 

(0.2

)

 

  1. Amounts relate to the re-measurement of Deferred Income Taxes as a result of Tax Reform. In accordance with the accounting guidance for “Income Taxes”, re-measurement of Deferred Income Taxes related to AOCI must flow through the statement of income.

 

 

 

Pension Plans

 

OPEB

 

 

2018

 

2017

 

2018

 

2017

Components

 

(in millions)

Actuarial (Gain) Loss During the Year

 

$

14.0

 

 

$

(11.1

)

 

$

14.9

 

 

$

(23.6

)

Amortization of Actuarial Loss

 

(7.2

)

 

(7.0

)

 

(0.8

)

 

(3.2

)

Amortization of Prior Service Credit

 

 

 

 

 

5.9

 

 

5.8

 

Change for the Year Ended December 31,

 

$

6.8

 

 

$

(18.1

)

 

$

20.0

 

 

$

(21.0

)

 

Determination of Pension Expense

 

The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility.  This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur.  Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return.


Pension and OPEB Assets

 

The fair value tables within Pension and OPEB Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to AEP Texas using the percentages in the table below:

Pension Plan

 

OPEB

December 31,

2018

 

2017

 

2018

 

2017

8.7

%

 

8.8

%

 

8.5

%

 

8.5

%

 

The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2018:

Asset Class

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

 

Year End

Allocation

 

 

(in millions)

 

 

Equities (a):

 

 

 

 

 

 

 

 

 

 

 

 

Domestic

 

$

277.3

 

 

$

 

 

$

 

 

$

 

 

$

277.3

 

 

5.9

%

International

 

384.1

 

 

 

 

 

 

 

 

384.1

 

 

8.2

%

Options

 

 

 

18.3

 

 

 

 

 

 

18.3

 

 

0.4

%

Common Collective Trusts (c)

 

 

 

 

 

 

 

370.1

 

 

370.1

 

 

7.9

%

Subtotal – Equities

 

661.4

 

 

18.3

 

 

 

 

370.1

 

 

1,049.8

 

 

22.4

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Income (a):

 

 

 

 

 

 

 

 

 

 

 

 

United States Government and Agency Securities

 

0.2

 

 

1,512.5

 

 

 

 

 

 

1,512.7

 

 

32.2

%

Corporate Debt

 

 

 

1,082.9

 

 

 

 

 

 

1,082.9

 

 

23.0

%

Foreign Debt

 

 

 

221.6

 

 

 

 

 

 

221.6

 

 

4.7

%

State and Local Government

 

 

 

28.2

 

 

 

 

 

 

28.2

 

 

0.6

%

Other Asset Backed

 

 

 

7.4

 

 

 

 

 

 

7.4

 

 

0.2

%

Subtotal Fixed Income

 

0.2

 

 

2,852.6

 

 

 

 

 

 

2,852.8

 

 

60.7

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Infrastructure (c)

 

 

 

 

 

 

 

72.2

 

 

72.2

 

 

1.5

%

Real Estate (c)

 

 

 

 

 

 

 

220.4

 

 

220.4

 

 

4.7

%

Alternative Investments (c)

 

 

 

 

 

 

 

444.6

 

 

444.6

 

 

9.5

%

Cash and Cash Equivalents (c)

 

(0.4

)

 

36.3

 

 

 

 

11.9

 

 

47.8

 

 

1.0

%

Other – Pending Transactions and Accrued Income (b)

 

 

 

 

 

 

 

8.3

 

 

8.3

 

 

0.2

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

661.2

 

 

$

2,907.2

 

 

$

 

 

$

1,127.5

 

 

$

4,695.9

 

 

100.0

%

 

  1. Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

  2. Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

  3. Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.

 

The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2018:

Asset Class

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

 

Year End

Allocation

 

 

(in millions)

 

 

Equities:

 

 

 

 

 

 

 

 

 

 

 

 

Domestic

 

$

233.3

 

 

$

 

 

$

 

 

$

 

 

$

233.3

 

 

15.2

%

International

 

185.9

 

 

 

 

 

 

 

 

185.9

 

 

12.1

%

Options

 

 

 

4.3

 

 

 

 

 

 

4.3

 

 

0.3

%

Common Collective Trusts (b)

 

 

 

 

 

 

 

226.2

 

 

226.2

 

 

14.7

%

Subtotal Equities

 

419.2

 

 

4.3

 

 

 

 

226.2

 

 

649.7

 

 

42.3

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Income:

 

 

 

 

 

 

 

 

 

 

 

 

Common Collective Trust Debt (b)

 

 

 

 

 

 

 

163.6

 

 

163.6

 

 

10.7

%

United States Government and Agency Securities

 

0.2

 

 

181.5

 

 

 

 

 

 

181.7

 

 

11.8

%

Corporate Debt

 

 

 

188.6

 

 

 

 

 

 

188.6

 

 

12.3

%

Foreign Debt

 

 

 

35.0

 

 

 

 

 

 

35.0

 

 

2.3

%

State and Local Government

 

41.8

 

 

11.8

 

 

 

 

 

 

53.6

 

 

3.5

%

Other Asset Backed

 

 

 

0.2

 

 

 

 

 

 

0.2

 

 

%

Subtotal Fixed Income

 

42.0

 

 

417.1

 

 

 

 

163.6

 

 

622.7

 

 

40.6

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Trust Owned Life Insurance:

 

 

 

 

 

 

 

 

 

 

 

 

International Equities

 

 

 

49.4

 

 

 

 

 

 

49.4

 

 

3.2

%

United States Bonds

 

 

 

154.4

 

 

 

 

 

 

154.4

 

 

10.1

%

Subtotal Trust Owned Life Insurance

 

 

 

203.8

 

 

 

 

 

 

203.8

 

 

13.3

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents (b)

 

54.4

 

 

 

 

 

 

4.8

 

 

59.2

 

 

3.9

%

Other – Pending Transactions and Accrued Income (a)

 

 

 

 

 

 

 

(1.2

)

 

(1.2

)

 

(0.1

)%

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

515.6

 

 

$

625.2

 

 

$

 

 

$

393.4

 

 

$

1,534.2

 

 

100.0

%

 

  1. Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

  2. Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.


The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2017:

Asset Class

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

 

Year End
Allocation

 

 

(in millions)

 

 

Equities (a):

 

 

 

 

 

 

 

 

 

 

 

 

Domestic

 

$

318.6

 

 

$

 

 

$

 

 

$

 

 

$

318.6

 

 

6.2

%

International

 

507.7

 

 

 

 

 

 

 

 

507.7

 

 

9.8

%

Options

 

 

 

26.9

 

 

 

 

 

 

26.9

 

 

0.5

%

Common Collective Trusts (c)

 

 

 

 

 

 

 

452.9

 

 

452.9

 

 

8.7

%

Subtotal Equities

 

826.3

 

 

26.9

 

 

 

 

452.9

 

 

1,306.1

 

 

25.2

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Income (a):

 

 

 

 

 

 

 

 

 

 

 

 

United States Government and Agency Securities

 

 

 

1,376.5

 

 

 

 

 

 

1,376.5

 

 

26.6

%

Corporate Debt

 

 

 

1,277.0

 

 

 

 

 

 

1,277.0

 

 

24.7

%

Foreign Debt

 

 

 

296.9

 

 

 

 

 

 

296.9

 

 

5.7

%

State and Local Government

 

 

 

31.7

 

 

 

 

 

 

31.7

 

 

0.6

%

Other Asset Backed

 

 

 

10.2

 

 

 

 

 

 

10.2

 

 

0.2

%

Subtotal Fixed Income

 

 

 

2,992.3

 

 

 

 

 

 

2,992.3

 

 

57.8

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Infrastructure (c)

 

 

 

 

 

 

 

59.5

 

 

59.5

 

 

1.2

%

Real Estate (c)

 

 

 

 

 

 

 

290.3

 

 

290.3

 

 

5.6

%

Alternative Investments (c)

 

 

 

 

 

 

 

446.0

 

 

446.0

 

 

8.6

%

Cash and Cash Equivalents (c)

 

0.4

 

 

35.6

 

 

 

 

21.2

 

 

57.2

 

 

1.1

%

Other – Pending Transactions and Accrued Income (b)

 

 

 

 

 

 

 

22.7

 

 

22.7

 

 

0.5

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

826.7

 

 

$

3,054.8

 

 

$

 

 

$

1,292.6

 

 

$

5,174.1

 

 

100.0

%

 

  1. Includes investment securities loaned to borrowers under the securities lending program. See the “Investments Held in Trust for Future Liabilities” section of Note 1 for additional information.

  2. Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

  3. Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.


The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets:

 

 

Infrastructure

 

Real

Estate

 

Alternative

Investments

 

Total

Level 3

 

 

(in millions)

Balance as of January 1, 2017

 

$

57.6

 

 

$

254.9

 

 

$

411.1

 

 

$

723.6

 

Actual Return on Plan Assets

 

 

 

 

 

 

 

 

Relating to Assets Still Held as of the Reporting Date

 

 

 

 

 

 

 

 

Relating to Assets Sold During the Period

 

 

 

 

 

 

 

 

Purchases and Sales

 

 

 

 

 

 

 

 

Transfers into Level 3

 

 

 

 

 

 

 

 

Transfers out of Level 3 (a)

 

(57.6

)

 

(254.9

)

 

(411.1

)

 

(723.6

)

Balance as of December 31, 2017

 

$

 

 

$

 

 

$

 

 

$

 

 


  1. The classification of Level 3 assets from the prior year was corrected in the current year presentation and included within the fair value hierarchy table as of December 31, 2017 as “Other” investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent). Management concluded that these disclosure errors were immaterial individually and in the aggregate to all prior periods presented. he following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2017:

Asset Class

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

 

Year End
Allocation

 

 

(in millions)

 

 

Equities:

 

 

 

 

 

 

 

 

 

 

 

 

Domestic

 

$

307.1

 

 

$

 

 

$

 

 

$

 

 

$

307.1

 

 

17.7

%

International

 

306.9

 

 

 

 

 

 

 

 

306.9

 

 

17.7

%

Options

 

 

 

9.4

 

 

 

 

 

 

9.4

 

 

0.5

%

Common Collective Trusts (b)

 

 

 

 

 

 

 

153.6

 

 

153.6

 

 

8.9

%

Subtotal Equities

 

614.0

 

 

9.4

 

 

 

 

153.6

 

 

777.0

 

 

44.8

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Fixed Income:

 

 

 

 

 

 

 

 

 

 

 

 

Common Collective Trust Debt (b)

 

 

 

 

 

 

 

185.0

 

 

185.0

 

 

10.7

%

United States Government and Agency Securities

 

 

 

187.4

 

 

 

 

 

 

187.4

 

 

10.8

%

Corporate Debt

 

 

 

214.1

 

 

 

 

 

 

214.1

 

 

12.4

%

Foreign Debt

 

 

 

40.7

 

 

 

 

 

 

40.7

 

 

2.4

%

State and Local Government

 

49.7

 

 

16.8

 

 

 

 

 

 

66.5

 

 

3.8

%

Other Asset Backed

 

 

 

0.2

 

 

 

 

 

 

0.2

 

 

%

Subtotal Fixed Income

 

49.7

 

 

459.2

 

 

 

 

185.0

 

 

693.9

 

 

40.1

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Trust Owned Life Insurance:

 

 

 

 

 

 

 

 

 

 

 

 

International Equities

 

 

 

105.4

 

 

 

 

 

 

105.4

 

 

6.1

%

United States Bonds

 

 

 

118.2

 

 

 

 

 

 

118.2

 

 

6.8

%

Subtotal Trust Owned Life Insurance

 

 

 

223.6

 

 

 

 

 

 

223.6

 

 

12.9

%

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and Cash Equivalents (b)

 

36.7

 

 

 

 

 

 

4.2

 

 

40.9

 

 

2.4

%

Other Pending Transactions and Accrued Income (a)

 

 

 

 

 

 

 

(2.9

)

 

(2.9

)

 

(0.2

)%

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

$

700.4

 

 

$

692.2

 

 

$

 

 

$

339.9

 

 

$

1,732.5

 

 

100.0

%

 

  1. Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

  2. Amounts in “Other” column represent investments for which fair value is measured using net asset value per share.


Accumulated Benefit Obligation

 

The accumulated benefit obligation for the pension plans was as follows:

 

 

December 31,

Accumulated Benefit Obligation

 

2018 

 

2017 

 

 

(in millions)

Qualified Pension Plan

 

$

393.2

 

$

421.4

Nonqualified Pension Plans

 

 

3.6

 

 

3.8

Total

 

$

396.8

 

$

425.2

 

Obligations in Excess of Fair Values

 

The tables below show the underfunded pension plans that had obligations in excess of plan assets.

 

Projected Benefit Obligation

 

 

 

December 31,

 

 

2018

 

2017

 

 

(in millions)

Projected Benefit Obligation

 

$

3.8

 

 

$

4.0

 

Fair Value of Plan Assets

 

 

 

 

Underfunded Projected Benefit Obligation

 

$

(3.8)

 

 

$

(4.0)

 

 

Accumulated Benefit Obligation

 

 

 

December 31,

 

 

2018

 

2017

 

 

(in millions)

Accumulated Benefit Obligation

 

$

3.6

 

 

$

3.8

 

Fair Value of Plan Assets

 

 

 

 

Underfunded Accumulated Benefit Obligation

 

$

(3.6)

 

 

$

(3.8)

 

 


Estimated Future Benefit Payments and Contributions

 

AEP Texas expects contributions and payments for the pension plans of $8 million during 2019. For the pension plans, this amount includes the payment of unfunded nonqualified benefits plus contributions to the qualified trust fund of at least the minimum amount required by the Employee Retirement Income Security Act. For the qualified pension plan, AEP Texas may also make additional discretionary contributions to maintain the funded status of the plan.

 

The table below reflects the total benefits expected to be paid from the plan or from AEP Texas’ assets.  The payments include the participants’ contributions to the plan for their share of the cost.  Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results.  The estimated payments for the pension benefits and OPEB are as follows:

 

 

Estimated Payments

 

 

Pension Plans

 

OPEB

 

 

(in millions)

2019

 

$

30.8

 

 

$

10.0

 

2020

 

34.3

 

 

10.5

 

2021

 

34.9

 

 

10.7

 

2022

 

33.5

 

 

10.9

 

2023

 

34.9

 

 

10.9

 

Years 2024 to 2028, in Total

 

164.7

 

 

53.6

 

 


Components of Net Periodic Benefit Cost

 

The following table provides the components of net periodic benefit cost (credit) for the plans:

 

Pension Plans

 

OPEB

 

Years Ended December 31,

 

2018

 

2017

 

2018

 

2017

 

(in millions)

Service Cost

$

9.2

 

 

$

8.6

 

 

$

0.9

 

$

0.9

 

Interest Cost

16.0

 

 

17.1

 

 

3.8

 

 

4.9

 

Expected Return on Plan Assets

(25.6

)

 

(25.0

)

 

(8.6

)

 

(8.8

)

Amortization of Prior Service Cost (Credit)

 

 

 

 

(5.9

)

 

(5.8

)

Amortization of Net Actuarial Loss

7.2

 

 

7.0

 

 

0.8

 

 

3.2

 

Net Periodic Benefit Cost (Credit)

6.8

 

 

7.7

 

 

(9.0

)

 

(5.6

)

Capitalized Portion

(4.8

)

 

(4.0

)

 

(0.5

)

 

2.9

 

Net Periodic Benefit Cost (Credit) Recognized in Expense

$

2.0

 

 

$

3.7

 

 

$

(9.5

)

 

$

(2.7

)

 

American Electric Power System Retirement Savings Plan

 

AEP Texas participates in an AEP sponsored defined contribution retirement savings plan, the American Electric Power System Retirement Savings Plan, for substantially all employees. This qualified plan offers participants an opportunity to contribute a portion of their pay, includes features under Section 401(k) of the Internal Revenue Code and provides for company matching contributions.  The matching contributions to the plan are 100% of the first 1% of eligible employee contributions and 70% of the next 5% of contributions. The cost for matching contributions to the retirement savings plans was $6 million for both years ended December 31, 2018 and 2017.

 

8.  BUSINESS SEGMENTS

 

AEP Texas has one reportable segment, an electricity transmission and distribution business. AEP Texas’ other activities are insignificant.

9.  DERIVATIVES AND HEDGING

 

AEP Texas adopted ASU 2017-12 in the second quarter of 2018, effective January 1, 2018. See Note 2 - New Accounting Pronouncements for additional information.

 

AEPSC is agent for and transacts on behalf of AEP Texas.

 

Risk Management Strategies

 

AEP Texas’ vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEP Texas utilizes financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. AEP Texas does not hedge all fuel price risk. The gross notional volumes of AEP Texas’ outstanding derivative contracts for heating oil and gasoline as of December 31, 2018 and 2017 were 2 million gallons and 1 million gallons, respectively.

 

Cash Flow Hedging Strategies

 

AEP Texas utilizes a variety of interest rate derivative transactions in order to manage interest rate risk exposure.  AEP Texas also utilizes interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt.  AEP Texas does not hedge all interest rate exposure.

 

ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS

 

The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value.  The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes.  If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions.  In order to determine the relevant fair values of the derivative instruments, AEP Texas applies valuation adjustments for discounting, liquidity and credit quality.

 

Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due.  Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions.  Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts.  Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles.  Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period.  This is particularly true for longer term contracts.  Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts.

 

According to the accounting guidance for “Derivatives and Hedging,” AEP Texas reflects the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral.  For certain risk management contracts, AEP Texas is required to post or receive cash collateral based on third-party contractual agreements and risk profiles. The netted cash collateral from third-parties against short-term and long-term risk management assets and netted cash collateral paid to third-parties against short-term and long-term risk management liabilities were immaterial as of December 31, 2018 and 2017.

The following tables represent the gross fair value of AEP Texas’ derivative activity on the balance sheets:

 

Fair Value of Derivative Instruments

December 31, 2018

 

 

Risk Management

 

Gross Amounts Offset

 

Net Amounts of Assets/Liabilities

 

 

Contracts -

 

in the Statement of

 

Presented in the Statement

Balance Sheet Location

 

Commodity (a)

 

Financial Position (b)

 

of Financial Position (c)

 

 

(in millions)

Derivative Instrument Assets

 

$

 

 

$

 

 

$

 

Long-Term Portion of Derivative Instrument Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Instrument Liabilities

 

0.7

 

 

(0.5

)

 

0.2

 

Long-Term Portion of Derivative Instrument Liabilities

 

 

 

 

 

 

 

Fair Value of Derivative Instruments

December 31, 2017

 

 

Risk Management

 

Gross Amounts Offset

 

Net Amounts of Assets/Liabilities

 

 

Contracts -

 

in the Statement of

 

Presented in the Statement

Balance Sheet Location

 

Commodity (a)

 

Financial Position (b)

 

of Financial Position (c)

 

 

(in millions)

Derivative Instrument Assets

 

$

0.5

 

 

$

 

 

$

0.5

 

Long-Term Portion of Derivative Instrument Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

Derivative Instrument Liabilities

 

 

 

 

 

 

Long-Term Portion of Derivative Instrument Liabilities

 

 

 

 

 

 

 

  1. Derivative instruments within this category are reported gross.  These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”

  2. Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”

  3. All derivative contracts subject to a master netting arrangement or similar agreement are offset in the statement of financial position.


The table below presents the activity of derivative risk management contracts:

 

Amount of Gain (Loss) Recognized on

Risk Management Contracts

 

 

 

Years Ended December 31,

Location of Gain (Loss)

 

2018

 

2017

 

 

(in millions)

Operating Expenses

 

$

0.4

 

$

0.1

Maintenance Expenses

 

 

0.4

 

 

0.2

Other Regulatory Assets (a)

 

 

(0.7)

 

 

Other Regulatory Liabilities (a)

 

 

(0.5)

 

 

0.1

Total Gain (Loss) on Risk Management Contracts

 

$

(0.4)

 

$

0.4

 

 

 

 

 

 

 

 

(a)

Represents realized and unrealized gains and losses subject to regulatory accounting treatment.

 

Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.”  Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis.

 

The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship.  Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge.

 

For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”

 

Accounting for Cash Flow Hedging Strategies

 

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), AEP Texas initially reports the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income on the balance sheets until the period the hedged item affects Net Income.

 

Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Operating Revenues or Operation Expenses on the statements of income or in Other Regulatory Assets or Other Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to outstanding power derivatives.

 

AEP Texas reclassifies gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income on the balance sheets into Interest on Long-Term Debt on the statements of income in those periods in which hedged interest payments occur.  During the years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to outstanding interest rate derivatives.

 

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income on the balance sheets into Depreciation Expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the years ended 2018 and 2017, AEP Texas did not apply cash flow hedging to any outstanding foreign currency derivatives.

 

For details on effective cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 - Comprehensive Income.


Cash flow hedges included in Accumulated Other Comprehensive Income on the balance sheets were:

Impact of Cash Flow Hedges on the Balance Sheets

December 31, 2018

 

December 31, 2017

Interest Rate

 

 

Expected to be

 

 

 

Expected to be

 

 

Reclassed to

 

 

 

Reclassed to

 

 

Net Income During

 

 

 

Net Income During

AOCI Gain (Loss)

 

the Next

 

AOCI Gain (Loss)

 

the Next

Net of Tax

 

Twelve Months

 

Net of Tax

 

Twelve Months

(in millions)

$

(4.4)

 

 

$

(1.1)

 

 

$

(4.5)

 

 

$

(0.9)

 

 

The actual amounts reclassified from Accumulated Other Comprehensive Income to Net Income can differ from the estimate above due to market price changes.

 

Credit Risk

 

Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses credit agency ratings and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

 

Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required.


10.  FAIR VALUE MEASUREMENTS

 

Fair Value Measurements of Long-term Debt

 

The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs.  These instruments are not marked-to-market.  The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

 

The book values and fair values of Long-term Debt are summarized in the following table:

December 31,

2018

 

2017

Book Value

 

Fair Value

 

Book Value

 

Fair Value

(in millions)

$

3,106.6

 

 

$

3,165.2

 

 

$

2,637.6

 

 

$

2,909.5

 


Fair Value Measurements of Financial Assets and Liabilities

 

For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1.

 

The following tables set forth, by level within the fair value hierarchy, AEP Texas’ financial assets and liabilities that were accounted for at fair value on a recurring basis.  As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.  There have not been any significant changes in management’s valuation techniques.

 

Assets and Liabilities Measured at Fair Value on a Recurring Basis

December 31, 2018

 

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

Liabilities:

 

(in millions)

Derivative Instrument Liabilities

 

 

 

 

 

 

 

 

 

 

Risk Management Commodity Contracts (a)

 

$

 

 

$

0.7

 

 

$

 

 

$

(0.5

)

 

$

0.2

 

 

December 31, 2017

 

 

Level 1

 

Level 2

 

Level 3

 

Other

 

Total

Assets:

 

(in millions)

Derivative Instrument Assets

 

 

 

 

 

 

 

 

 

 

Risk Management Commodity Contracts (a)

 

$

 

 

$

0.5

 

 

$

 

 

$

 

 

$

0.5

 

 

  1. Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”

 

There were no transfers between Level 1 and Level 2 during the years ended December 31, 2018 and 2017.

 

11. INCOME TAXES

 

Federal Tax Reform and Legislation

 

In December 2017, Tax Reform legislation was signed into law. Tax Reform includes significant changes to the Internal Revenue Code of 1986, as amended, including lowering the corporate federal income tax rate from 35% to 21%. As a result of this rate change, AEP Texas’ deferred tax assets and liabilities were remeasured using the newly enacted rate of 21% in December 2017. In response to Tax Reform, the SEC staff issued Staff Accounting Bulletin 118 (SAB 118) in December 2017. SAB 118 provided for up to a one year period (the measurement period) in which to complete the required analyses and accounting required by Tax Reform.

 

During 2017, AEP Texas recorded provisional amounts for the income tax effects of Tax Reform.  Throughout 2018, AEP Texas continued to assess the impacts of legislative changes in the tax code as well as interpretative changes of the tax code. The measurement period adjustments recorded during 2018 were immaterial.

 

The measurement period under SAB 118 ended in December 2018.  However, Tax Reform uncertainties still remain and AEP Texas will continue to monitor income tax effects that may change as a result of future legislation and further interpretation of Tax Reform based on proposed U.S. Treasury regulations and guidance from the IRS and state tax authorities.

 

Federal Legislation

 

The IRS has proposed new regulations that provide guidance regarding the additional first-year depreciation deduction under Section 168(k). The proposed regulations reflect changes as a result of Tax Reform and affect taxpayers with qualified depreciable property acquired and placed in service after September 27, 2017. Generally, AEP Texas’ regulated businesses will not be eligible for any bonus depreciation for property acquired and placed in service after January 1, 2018. However, for self-constructed property and other property placed in service in 2018 for which construction began prior to January 1, 2018, taxpayers are required to evaluate the contractual terms to determine if these additions qualify for 100% expensing under Tax Reform or 50% bonus depreciation as provided under prior tax law.

 

Excess and Deficient Accumulated Deferred Income Taxes as Result of Tax Reform

 

Accounting guidance for “Income Taxes” requires deferred tax assets and liabilities to be measured at the enacted income tax rate expected to apply when the related temporary differences will be realized or settled. As a result, AEP Texas’ deferred tax assets and liabilities were re-measured in December 2017 using the newly enacted tax rate of 21% resulting in excess or deficient accumulated deferred income taxes (“ADIT”).

 

With respect to the AEP Texas’ regulated operations, the change to net deferred income taxes was primarily offset by a corresponding change in net income tax related regulatory assets and liabilities to reflect amounts expected to be provided to customers. Where the deferred income tax amount was not previously contemplated in regulated rates or pertained to unregulated operations, the re-measurement was recorded as an adjustment to income tax expense.

 

The FERC accounts affected by the re-measurement of ADIT include:

 

182.3 Other Regulatory Assets

190 Accumulated Deferred Income Taxes

254 Other Regulatory Liabilities

281 Accumulated Deferred Income Taxes – Accelerated Amortization

282 Accumulated Deferred Income Taxes – Other Property

283 Accumulated Deferred Income Taxes – Other

410.1 Provision for Deferred Income Taxes, Utility Operating Income

410.2 Provision for Deferred Income Taxes, Utility Non-Operating Income

411.1 Provision for Deferred Income Taxes – Credit, Utility Operating Income

411.2 Provision for Deferred Income Taxes – Credit, Utility Non-Operating Income


Tax Reform included certain rate normalization requirements that stipulate how the portion of total excess or deficient ADIT that is related to certain depreciable property must be returned to customers. Specifically, regulated public utilities subject to these rate normalization requirements must recognize the impact of re-measured deferred taxes applicable to prior depreciation using an average rate assumption method. As a result, once the amortization of Excess ADIT is reflected in rates, customers will receive the benefits over the remaining weighted average useful life of the applicable property. The remaining balance of excess or deficient ADIT will be returned to customers via the mechanisms and time periods as agreed to and/or ordered by the PUCT. See “AEP Texas Interim Transmission and Distribution Rates” section of Note 4 - Rate Matters for additional information.

 

As of December 31, 2018, AEP Texas had recorded a regulatory liability for approximately $530 million of Excess ADIT as well as an incremental liability of $141 million to reflect the Excess ADIT on a pretax basis which is presented in Other Regulatory Liabilities on the balance sheet. $417 million of the Excess ADIT relates to temporary differences associated with certain depreciable property.

 

During 2018, AEP Texas recognized $12 million of amortization of Excess ADIT within Provisions for Deferred Income Taxes – Credit, Utility Operating Income on the statements of income.

 

Income Tax Expense (Benefit)

The details of AEP Texas’ Income Tax Expense (Benefit) are as follows:

 

 

Years Ended December 31,

 

2018

 

2017

 

(in millions)

Charged (Credited) to Operating Expenses, Net:

 

 

 

 

 

 

Current

$

36.5

 

$

(95.6)

 

Deferred

 

(11.5)

 

 

83.7

 

Deferred Investment Tax Credits

 

(1.5)

 

 

(1.6)

Total

 

23.5

 

 

(13.5)

 

 

 

 

 

 

Charged (Credited) to Nonoperating Income, Net:

 

 

 

 

 

 

Current

 

2.3

 

 

11.1

 

Deferred

 

(5.0)

 

 

(20.8)

Total

 

(2.7)

 

 

(9.7)

Total Income Taxes (Benefit)

$

20.8

 

$

(23.2)

 


The following is a reconciliation between the federal income taxes computed by multiplying pretax income by the federal statutory tax rate and the income taxes reported:

 

 

Years Ended December 31,

 

2018

 

2017

 

 

(in millions)

 

Net Income

$

211.3

 

 

$

311.1

 

 

Income Tax Expense (Benefit)

20.8

 

 

(23.2)

 

 

Pretax Income

$

232.1

 

 

$

287.9

 

 

 

 

 

 

 

Income Taxes on Pretax Income at Statutory Rate (21% and 35% in 2018 and 2017, Respectively)

$

48.7

 

 

$

100.8

 

 

Increase (Decrease) in Income Taxes Resulting from the Following Items:

 

 

 

 

State and Local Income Taxes, Net

1.3

 

 

0.4

)

 

AFUDC

(4.2)

 

 

(3.9)

)

 

Parent Company Loss Benefit

(3.1)

 

 

)

 

Tax Reform Adjustments

(11.0)

 

 

(119.2)

 

 

Tax Adjustments

 

 

(2.5)

)

 

Tax Reform Excess ADIT Reversal

(11.8)

 

 

 

 

Other

0.9

 

 

1.2

)

 

Income Tax Expense (Benefit)

$

20.8

 

 

$

(23.2)

 

 

 

 

 

 

 

Effective Income Tax Rate

9.0

 

%

 

(8.1)

 

%

 


Net Deferred Tax Liability

 

The following table shows elements of AEP Texas’ net deferred tax liability and significant temporary differences:

 

 

December 31,

 

2018

 

2017

 

(in millions)

Deferred Tax Assets

$

207.9

 

 

$

220.7

 

Deferred Tax Liabilities

(1,121.2)

 

 

(1,096.0)

 

Net Deferred Tax Liabilities

$

(913.3)

 

 

$

(875.3)

 

 

 

 

 

Property Related Temporary Differences

$

(836.4)

 

 

$

(753.4)

 

Amounts Due to Customers for Future Federal Income Taxes

142.3

 

 

140.9

 

Deferred State Income Taxes

(27.1)

 

 

(27.5)

 

Regulatory Assets

(53.9)

 

 

(65.2)

 

Securitized Transition Assets

(144.4)

 

 

(190.5)

 

Deferred Income Taxes on Other Comprehensive Loss

4.0

 

 

4.1

 

Deferred Revenues

4.6

 

 

18.9

 

All Other, Net

(2.4)

 

 

(2.6)

 

Net Deferred Tax Liabilities

$

(913.3)

 

 

$

(875.3)

 

 

AEP System Tax Allocation Agreement

 

AEP Texas joins in the filing of a consolidated federal income tax return with its affiliates in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent and tax credits, the method of allocation reflects a separate return result for each company in the consolidated group.

 

Federal and State Income Tax Audit Status

 

AEP Texas and other AEP subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011 through 2013 started in April 2014. AEP Texas and other AEP subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. To resolve the issue under consideration, AEP Texas and other AEP subsidiaries and the IRS exam team agreed to utilize the Fast Track Settlement Program in December 2017. The program was completed in March 2018 and tax years 2014 and 2015 were added to the IRS examination to reflect the impact of the Fast Track changes that were carried forward to 2014 and 2015. In June 2018, AEP Texas and other AEP subsidiaries settled all outstanding issues under audit for tax years 2011-2015. The Joint Committee approved the settlement in November 2018. The settlement did not materially impact AEP Texas’ net income, cash flows or financial condition. The IRS examination of 2016 began in October 2018.

 

AEP Texas and other AEP subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns. AEP Texas and other AEP subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. AEP Texas is no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2007.

 

Uncertain Tax Positions

 

The reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

 

 

2018

 

2017

 

 

(in millions)

Balance as of January 1,

 

$

(0.8)

 

$

6.5

Increase – Tax Positions Taken During a Prior Period

 

 

 

 

2.0

Decrease – Tax Positions Taken During a Prior Period

 

 

 

 

(12.3)

Increase – Tax Positions Taken During the Current Year

 

 

 

 

Decrease – Tax Positions Taken During the Current Year

 

 

 

 

Increase – Settlements with Taxing Authorities

 

 

 

 

Decrease – Settlements with Taxing Authorities

 

 

 

 

3.0

Decrease – Lapse of the Applicable Statute of Limitations

 

 

 

 

Balance as of December 31,

 

$

(0.8)

 

$

(0.8)

 

The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate is $1 million and $1 million for 2018 and 2017, respectively. Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date.

 

State Tax Legislation

 

In June 2018, the United States Supreme Court issued a decision which eliminated a physical presence requirement for the imposition of sales and use tax and instead applied an economic nexus concept.  Although this case was specific to sales and use taxes, many states are beginning to consider whether they could also apply this economic nexus concept to income taxes.  Management continues to monitor state legislation to determine whether it could create any income tax liability in any states in which AEP Texas currently does not file.

 

12.  LEASES

 

Leases of property, plant and equipment are for remaining periods up to 10 years and require payments of related property taxes, maintenance and operating costs.  Many of the leases have purchase or renewal options. Leases not renewed are often replaced by other leases.

 

Lease rentals for both operating and capital leases are generally charged to Operation Expenses and Maintenance Expenses in accordance with rate-making treatment for regulated operations. The components of rental costs were as follows:

 

 

Years Ended December 31,

 

 

2018

 

2017

 

 

(in millions)

Net Lease Expense on Operating Leases

 

$

13.6

 

$

10.5

Amortization of Capital Leases

 

 

4.8

 

 

4.0

Interest on Capital Leases

 

 

1.2

 

 

0.8

Total Lease Rental Costs

 

$

19.6

 

$

15.3

 

The following table shows the property, plant and equipment under capital leases and related obligations recorded on AEP Texas’ balance sheets.  

 

 

December 31,

 

 

2018

 

2017

 

 

 

(in millions)

Property, Plant and Equipment Under Capital Leases

 

 

 

 

 

 

Total Property, Plant and Equipment

 

$

38.8

 

$

32.7

Accumulated Amortization

 

 

10.3

 

 

10.0

Net Property, Plant and Equipment Under Capital Leases

 

$

28.5

 

$

22.7

 

 

 

 

 

 

 

 

Obligations Under Capital Leases:

 

 

 

 

 

 

Noncurrent

 

$

24.0

 

$

18.5

Current

 

 

4.5

 

 

4.2

Total Obligations Under Capital Leases

 

$

28.5

 

$

22.7

 


Future minimum lease payments consisted of the following as of December 31, 2018:

 

 

 

 

Noncancelable

 

 

Capital

 

Operating

 

 

Leases

 

Leases

 

(in millions)

2019

 

$

5.8

 

$

15.1

2020 

 

 

5.3

 

 

14.1

2021 

 

 

4.7

 

 

13.2

2022 

 

 

4.2

 

 

12.2

2023

 

 

3.7

 

 

10.8

Later Years

 

 

10.1

 

 

28.4

Total Future Minimum Lease Payments

 

 

33.8

 

$

93.8

Less Estimated Interest Element

 

 

5.3

 

 

 

Estimated Present Value of Future Minimum Lease Payments

 

$

28.5

 

 

 

 

Master Lease Agreements

 

AEP Texas leases certain equipment under master lease agreements.  Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, AEP Texas is committed to pay the difference between the actual fair value and the residual value guarantee.  Historically, at the end of the lease term the fair value has been in excess of the amount guaranteed.  As of December 31, 2018, the maximum potential loss by AEP Texas for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was $11 million.

 


13.  FINANCING ACTIVITIES

 

Long-term Debt

 

The following table details long-term debt outstanding:

 

 

 

 

Weighted-Average

 

Interest Rate Ranges as of

 

Outstanding as of

 

 

 

 

Interest Rate as of

 

December 31,

 

December 31,

 

 

Maturity

 

December 31, 2018

 

2018

 

2017

 

2018

 

2017

 

 

 

 

 

 

 

 

 

 

(in millions)

Senior Unsecured Notes

 

2019-2047

 

4.06%

 

2.40%-6.76%

 

2.40%-6.76%

 

$

2,420.0

 

 

$

1,950.0

 

Pollution Control Bonds

 

2020-2030

 

4.39%

 

1.75%-6.30%

 

1.75%-6.30%

 

493.2

 

 

493.2

 

Other Long-term Debt

 

2019-2059

 

3.94%

 

3.94%-4.50%

 

2.75%-4.50%

 

201.0

 

 

201.0

 

Unamortized Discount, Net

 

 

 

 

 

 

 

 

 

(7.6

)

 

(6.6

)

Total Long-term Debt

 

 

 

 

 

 

 

 

 

$

3,106.6

 

 

$

2,637.6

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

As of December 31, 2018, long-term debt was payable as follows:

 

 

(in millions)

2019

 

$

250.0

2020 

 

 

110.6

2021 

 

 

2022 

 

 

425.0

2023

 

 

125.0

After 2023

 

 

2,203.6

Principal Amount

 

 

3,114.2

Unamortized Discount, Net

 

 

(7.6)

Total Long-term Debt

 

$

3,106.6

 

Dividend Restrictions

 

AEP Texas pays dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of AEP Texas to transfer funds to Parent in the form of dividends.

 

All of the dividends declared by AEP Texas are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only.

 

AEP Texas has credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5%. The method for calculating outstanding debt and capitalization is contractually-defined in the credit agreements.

 

The most restrictive dividend limitation for AEP Texas is through the credit agreements. As of December 31, 2018, the maximum amount of restricted net assets of AEP Texas that may not be distributed to the Parent in the form of a loan, advance or dividend was $1.6 billion.

 

The credit agreement covenant restrictions can limit the ability of AEP Texas to pay dividends out of retained earnings. As of December 31, 2018, the amount of any such restrictions was $354 million.


Corporate Borrowing Program – AEP System

 

The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries.  The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC.  The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2018 and 2017 are included in Notes Receivable from Associated Companies and Notes Payable to Associated Companies, respectively, on the balance sheets.  AEP Texas’ money pool activity and their corresponding authorized borrowing limits are described in the following table:

 

 

Maximum

 

 

 

Average

 

 

 

Loans to

 

 

 

 

Borrowings

 

Maximum

 

Borrowings

 

Average

 

(Borrowings from)

 

Authorized

 

 

from the

 

Loans to the

 

from the

 

Loans to the

 

the Utility Money

 

Short-term

Years Ended

 

Utility

 

Utility

 

Utility

 

Utility

 

Pool as of

 

Borrowing

December 31,

 

Money Pool

 

Money Pool

 

Money Pool

 

Money Pool

 

December 31,

 

Limit

 

 

(in millions)

2018

 

$

390.6

 

 

$

106.9

 

 

$

176.0

 

 

$

47.1

 

 

$

(216.0

)

 

$

500.0

 

2017

 

296.0

 

 

451.7

 

 

194.8

 

 

264.6

 

 

103.5

 

 

400.0

 

 

The maximum, minimum and average interest rates for funds either borrowed from or loaned to the Utility Money Pool are summarized in the following table:

 

 

Maximum

 

Minimum

 

Maximum

 

Minimum

 

Average

 

Average

 

 

Interest Rates

 

Interest Rates

 

Interest Rates

 

Interest Rates

 

Interest Rate

 

Interest Rate

 

 

for Funds

 

for Funds

 

for Funds

 

for Funds

 

for Funds

 

for Funds

 

 

Borrowed from

 

Borrowed from

 

Loaned to the

 

Loaned to the

 

Borrowed from

 

Loaned to the

Years Ended

 

the Utility

 

the Utility

 

Utility Money

 

Utility Money

 

the Utility

 

Utility Money

December 31,

 

Money Pool

 

Money Pool

 

Pool

 

Pool

 

Money Pool

 

Pool

2018

 

2.97%

 

1.81%

 

2.51%

 

1.85%

 

2.26%

 

2.29%

2017

 

1.49%

 

0.92%

 

1.85%

 

1.12%

 

1.29%

 

1.26%

 

Interest expense and interest income related to the Utility Money Pool financing relationship are included in Interest on Debt to Associated Companies and Interest and Dividend Income, respectively, on the statements of income.  The interest expense and interest income related to the corporate borrowing programs were immaterial for the years ended December 31, 2018 and 2017.

 

Credit Facilities

 

For a discussion of credit facilities, see “Letters of Credit” section of Note 6 - Commitments, Guarantees and Contingencies.

 

14.  RELATED PARTY TRANSACTIONS

 

For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 11 - Income Taxes in addition to “Corporate Borrowing Program – AEP System” section of Note 13 - Financing Activities.


Affiliated Revenues and Purchases

 

The following table shows the revenues derived from direct sales to affiliates, auction sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2018 and 2017:

 

 

Years Ended December 31,

Related Party Revenues

 

 

2018

 

 

2017

 

 

(in millions)

Direct Sales to AEPEP

 

$

103.6

 

$

63.6

Other Revenues

 

 

1.6

 

 

2.1

 

ERCOT Transmission Service Charges

 

Pursuant to an order from the PUCT, ETT bills AEP Texas for its ERCOT wholesale transmission services. ETT billed AEP Texas $27 million and $30 million for transmission services in 2018 and 2017, respectively. The billings are recorded in Operation Expenses on AEP Texas’ statements of income.

 

Oklaunion PPA between AEP Texas and AEPEP

 

In 2007, AEP Texas entered into a PPA with an affiliate, AEPEP, whereby AEP Texas agrees to sell AEPEP 100% of AEP Texas’ capacity and associated energy from its undivided interest (54.69%) in the Oklaunion Power Station. AEPEP pays AEP Texas for the capacity and associated energy delivered to the delivery point, the sum of fuel, operation and maintenance, depreciation, capacity and all taxes other than federal income taxes applicable. A portion of the payment is fixed and is payable regardless of the level of output. There are no penalties if AEP Texas fails to maintain a minimum availability level or exceeds a maximum heat rate level. The PPA was approved by the FERC. AEP Texas recognizes revenues for the fuel, operations and maintenance and all other taxes as-billed. Revenue is recognized for the capacity and depreciation billed to AEPEP, on a straight-line basis over the term of the PPA as these represent the minimum payments due. In September 2018, the co-owners of Oklaunion Power Station voted to close the plant in 2020. Effective October 2018, AEP Texas increased depreciation expense to ensure the plant balances are fully depreciated as of September 2020 and recovered through the PPA billings to AEPEP. Under the early termination provisions of the PPA, AEPEP expects to pay AEP Texas the full Utility Plant balance through depreciation payments over the remaining period of operation of the plant, which is currently estimated to be September 2020.

 

AEP Texas recorded revenue of $104 million and $64 million from AEPEP for the years ended December 31, 2018 and 2017, respectively. These amounts are included in Operating Revenues on AEP Texas’ statements of income.


Sales and Purchases of Property

 

AEP Texas had affiliated sales and purchases of electric property amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property.  There were no gains or losses recorded on the transactions.  The following table shows the sales and purchases, recorded at net book value, for the years ended December 31, 2018 and 2017:

 

 

Years Ended December 31,

 

 

2018 

 

2017

 

 

(in millions)

Sales

 

$

0.3

 

$

0.2

Purchases

 

 

0.1

 

 

0.4

 

The amounts above are recorded in Utility Plant on the balance sheets.

 

Intercompany Billings

 

AEP Texas and other AEP subsidiaries perform certain utility services for each other when necessary or practical.  The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies.  The billings for services are made at cost and include no compensation for the use of equity capital.

 

AEPSC

 

AEPSC provides certain managerial and professional services to AEP Texas. The costs of the services are based on a direct charge or on a prorated basis and billed to AEP Texas at AEPSC’s cost. AEPSC and its billings are subject to regulation by the FERC. AEP Texas’ total billings from AEPSC were $188 million and $153 million for the years ended December 31, 2018 and 2017, respectively.

 

15.  PROPERTY, PLANT AND EQUIPMENT

 

Depreciation

 

AEP Texas provides for depreciation of Utility Plant on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.  The following table provides total regulated annual composite depreciation rates by functional class:

Year

 

Steam

 

Transmission

 

Distribution

 

General

 

 

(in percentages)

2018

 

 

7.2

 

 

1.7

 

 

3.6

 

 

6.0

2017

 

 

2.4

 

 

1.7

 

 

3.6

 

 

8.7

 

The composite depreciation rate generally includes a component for non-ARO removal costs, which is credited to accumulated depreciation on the balance sheets.  Actual removal costs incurred are charged to accumulated depreciation.

 

Asset Retirement Obligations

 

AEP Texas records ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, wind farms and certain coal mining facilities.   AEP Texas has identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned.  Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use.  The retirement obligation is not estimable for such easements since AEP Texas plans to use its facilities indefinitely.  The retirement obligation would only be recognized if and when AEP Texas abandons or ceases the use of specific easements, which is not expected.

 

The following is a reconciliation of the 2018 and 2017 aggregate carrying amounts of ARO:

 

 

 

 

 

 

 

 

 

Revisions in

 

 

 

 

 

ARO at

 

Accretion

 

Liabilities

 

Cash Flow

 

ARO at

Year

 

January 1,

 

Expense

 

Settled

 

Estimates

 

December 31,

 

 

(in millions)

2018

 

$

26.1

 

$

1.2

 

$

(0.1)

 

$

0.1

 

$

27.3

2017

 

 

25.0

 

 

1.1

 

 

(0.1)

 

 

0.1

 

 

26.1

 


Jointly-owned Electric Facilities

 

AEP Texas has electric facilities that are jointly-owned with affiliated and nonaffiliated companies.  Using its own financing, AEP Texas is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest.  AEP Texas’ proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Utility Plant as follows:

 

 

 

 

 

 

 

Construction

 

 

 

Fuel

 

Percent of

 

Utility Plant

 

Work in

 

Accumulated

 

Type

 

Ownership

 

In Service

 

Progress

 

Depreciation

 

 

 

 

 

(in millions)

AEP Texas’ Share as of December 31, 2018

 

 

 

 

 

 

 

 

 

Oklaunion Power Station (a)

Coal

 

54.7

%

 

$

352.1

 

 

$

0.2

 

 

$

218.6

 

 

 

 

 

 

 

 

 

 

 

AEP Texas’ Share as of December 31, 2017

 

 

 

 

 

 

 

 

 

Oklaunion Power Station (a)

Coal

 

54.7

%

 

$

350.7

 

 

$

1.3

 

 

$

194.1

 

 

 

 

 

 

 

 

 

 

 

 

  1. Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by AEP Texas and various nonaffiliated companies.


16. REVENUE FROM CONTRACTS WITH CUSTOMERS

 

Disaggregated Revenues from Contracts with Customers

The following table represents AEP Texas’ revenues from contracts with customers, net of respective provisions for refund, by type of revenue:

 

 

Twelve Months Ended

 

 

December 31, 2018

 

 

(in millions)

Retail Revenues:

 

 

Residential Revenues

 

$

462.4

 

Commercial Revenues

 

307.5

 

Industrial Revenues

 

78.7

 

Other Retail Revenues

 

23.8

 

Total Retail Revenues

 

872.4

 

 

 

 

Wholesale Revenues:

 

 

Transmission Revenues

 

313.4

 

Total Wholesale Revenues

 

313.4

 

 

 

 

Other Revenues from Contracts with Customers (a)

 

27.0

 

 

 

 

Total Revenues from Contracts with Customers

 

1,212.8

 

 

 

 

Other Revenues:

 

 

Alternative Revenues

 

(1.3

)

Other Revenues (a)

 

110.9

 

Total Other Revenues

 

109.6

 

 

 

 

Total Operating Revenues

 

$

1,322.4

 

 

  1. Amounts include affiliated and nonaffiliated revenues.


Performance Obligations

 

AEP Texas has performance obligations as part of its normal course of business. A performance obligation is a promise to transfer a distinct good or service, or a series of distinct goods or services that are substantially the same and have the same pattern of transfer to a customer. The invoice practical expedient within the accounting guidance for “Revenue from Contracts with Customers” allows for the recognition of revenue from performance obligations in the amount of consideration to which there is a right to invoice the customer and when the amount for which there is a right to invoice corresponds directly to the value transferred to the customer.

 

The purpose of the invoice practical expedient is to depict an entity’s measure of progress toward completion of the performance obligation within a contract and can only be applied to performance obligations that are satisfied over time and when the invoice is representative of services provided to date. AEP Texas elected to apply the invoice practical expedient to recognize revenue for performance obligations satisfied over time as the invoices from the respective revenue streams are representative of services or goods provided to date to the customer. Performance obligations for AEP Texas are summarized as follows:

 

Retail Revenues

 

AEP Texas has performance obligations to generate, transmit and distribute electricity for sale to rate-regulated retail customers. The performance obligation to deliver electricity is satisfied over time as the customer simultaneously receives and consumes the benefits provided. Revenues are variable as they are subject to the customer’s usage requirements.

 

Rate-regulated retail customers typically have the right to discontinue receiving service at will, therefore these contracts between AEP Texas and their customers for rate-regulated services are generally limited to the services requested and received to date for such arrangements. Retail customers are generally billed on a monthly basis, and payment is typically due within 15 to 20 days after the issuance of the invoice. Payments from Retail Electric Providers are due to AEP Texas within 35 days.

 

Wholesale Revenues - Transmission

 

AEP Texas has performance obligations to transmit electricity to wholesale customers through assets owned and operated. The performance obligation to provide transmission services in ERCOT encompass a time frame greater than a year, where the performance obligation within ERCOT is partially fixed for a period of one year or less. Payments from ERCOT for transmission services are typically received within one week from the issuance of the invoice, which is issued monthly for ERCOT.


AEP Texas within the ERCOT region collect revenues through a combination of base rates and interim Transmission Costs of Services filings that are approved by the PUCT.

 

Fixed Performance Obligations

 

The following table represents the remaining fixed performance obligations satisfied over time as of December 31, 2018. Fixed performance obligations primarily include wholesale transmission services and electricity sales for fixed amounts of energy. The amounts below include affiliated and nonaffiliated revenues.

2019

 

2020-2021

 

2022-2023

 

After 2024

 

Total

(in millions)

$

332.8

 

 

$

 

 

$

 

 

$

 

 

$

332.8

 

 

Contract Assets and Liabilities

 

Contract assets are recognized when AEP Texas has a right to consideration that is conditional upon the occurrence of an event other than the passage of time, such as future performance under a contract. AEP Texas did not have any material contract assets as of December 31, 2018.

 

When AEP Texas receives consideration, or such consideration is unconditionally due from a customer prior to transferring goods or services to the customer under the terms of a sales contract, they recognize a contract liability on the balance sheets in the amount of that consideration. Revenue for such consideration is subsequently recognized in the period or periods in which the remaining performance obligations in the contract are satisfied. AEP Texas’ contract liabilities typically arise from services provided under joint use agreements for utility poles. AEP Texas did not have any material contract liabilities as of December 31, 2018.

 

Accounts Receivable from Contracts with Customers

 

Accounts receivable from contracts with customers are presented on AEP Texas’ balance sheets within the Customer Accounts Receivable line item. AEP Texas’ balances for receivables from contracts that are not recognized in accordance with the accounting guidance for “Revenue from Contracts with Customers” included in Customer Accounts Receivable were not material as of December 31, 2018.

 

Affiliated accounts receivable from contracts with customers included in Accounts Receivable from Associated Companies on AEP Texas’ balance sheets were immaterial as of December 31, 2018 and January 1, 2018.

 

Contract Costs

 

Contract costs to obtain or fulfill a contract for AEP Texas are accounted for under the guidance for “Other Assets and Deferred Costs” and presented as a single asset and are neither bifurcated nor reclassified between current assets and deferred debits on the balance sheets. Contract costs to acquire a contract are amortized in a manner consistent with the transfer of goods or services to the customer in Operation Expenses on the income statements. AEP Texas did not have material contract costs as of December 31, 2018.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
9,518,192
5,358,052
14,876,244
2
Preceding Quarter/Year to Date Reclassifications from Account 219 to Net Income
264,139
868,873
1,133,012
3
Preceding Quarter/Year to Date Changes in Fair Value
1,093,655
1,093,655
4
Total (lines 2 and 3)
1,357,794
868,873
2,226,667
311,141,076
313,367,743
5
Balance of Account 219 at End of Preceding Quarter/Year
8,160,398
4,489,179
12,649,577
6
Balance of Account 219 at Beginning of Current Year
8,160,398
4,489,179
12,649,577
7
Current Quarter/Year to Date Reclassifications from Account 219 to Net Income
215,257
1,056,015
1,271,272
8
Current Quarter/Year to Date Changes in Fair Value
2,802,559
966,900
3,769,459
9
Total (lines 7 and 8)
2,587,302
89,115
2,498,187
211,345,402
208,847,215
10
Balance of Account 219 at End of Current Quarter/Year
10,747,700
4,400,064
15,147,764


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
7,630,043,940
7,630,043,940
4
UtilityPlantInServicePropertyUnderCapitalLeases
Property Under Capital Leases
28,482,207
28,482,207
5
UtilityPlantInServicePlantPurchasedOrSold
Plant Purchased or Sold
6
UtilityPlantInServiceCompletedConstructionNotClassified
Completed Construction not Classified
1,128,090,081
1,128,090,081
7
UtilityPlantInServiceExperimentalPlantUnclassified
Experimental Plant Unclassified
8
UtilityPlantInServiceClassifiedAndUnclassified
Total (3 thru 7)
8,786,616,228
8,786,616,228
9
UtilityPlantLeasedToOthers
Leased to Others
10
UtilityPlantHeldForFutureUse
Held for Future Use
4,941,592
4,941,592
11
ConstructionWorkInProgress
Construction Work in Progress
836,188,274
836,188,274
12
UtilityPlantAcquisitionAdjustment
Acquisition Adjustments
1,845,431
1,845,431
13
UtilityPlantAndConstructionWorkInProgress
Total Utility Plant (8 thru 12)
9,629,591,525
9,629,591,525
14
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Accumulated Provisions for Depreciation, Amortization, & Depletion
2,284,845,318
2,284,845,318
15
UtilityPlantNet
Net Utility Plant (13 less 14)
7,344,746,207
7,344,746,207
16
DetailOfAccumulatedProvisionsForDepreciationAmortizationAndDepletionAbstract
DETAIL OF ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION
17
AccumulatedProvisionForDepreciationAmortizationAndDepletionUtilityPlantInServiceAbstract
In Service:
18
DepreciationUtilityPlantInService
Depreciation
2,217,252,691
2,217,252,691
19
AmortizationAndDepletionOfProducingNaturalGasLandAndLandRightsutilityPlantInService
Amortization and Depletion of Producing Natural Gas Land and Land Rights
20
AmortizationOfUndergroundStorageLandAndLandRightsutilityPlantInService
Amortization of Underground Storage Land and Land Rights
21
AmortizationOfOtherUtilityPlantUtilityPlantInService
Amortization of Other Utility Plant
65,747,196
65,747,196
22
DepreciationAmortizationAndDepletionUtilityPlantInService
Total in Service (18 thru 21)
2,282,999,887
2,282,999,887
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
1,845,431
1,845,431
33
AccumulatedProvisionForDepreciationAmortizationAndDepletionOfPlantUtility
Total Accum Prov (equals 14) (22,26,30,31,32)
2,284,845,318
2,284,845,318


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
4
Allowance for Funds Used during Construction
5
(Other Overhead Construction Costs, provide details in footnote)
6
SUBTOTAL (Total 2 thru 5)
7
Nuclear Fuel Materials and Assemblies
8
In Stock (120.2)
9
In Reactor (120.3)
10
SUBTOTAL (Total 8 & 9)
11
Spent Nuclear Fuel (120.4)
12
Nuclear Fuel Under Capital Leases (120.6)
13
(Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)
14
TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)
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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
21,968
21,968
3
(302) Franchise and Consents
4
(303) Miscellaneous Intangible Plant
120,195,575
36,876,850
13,119,355
16,188
143,936,882
5
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4)
120,217,543
36,876,850
13,119,355
16,188
143,958,850
6
2. PRODUCTION PLANT
7
A. Steam Production Plant
8
(310) Land and Land Rights
6,241,380
6,241,380
9
(311) Structures and Improvements
49,181,356
1,094,440
154,906
50,120,890
10
(312) Boiler Plant Equipment
177,260,037
924,241
547,439
177,636,839
11
(313) Engines and Engine-Driven Generators
12
(314) Turbogenerator Units
65,129,400
65,129,400
13
(315) Accessory Electric Equipment
25,289,588
19,069
7,225
25,301,432
14
(316) Misc. Power Plant Equipment
7,201,391
32,914
4,676
7,229,629
15
(317) Asset Retirement Costs for Steam Production
20,417,918
20,417,918
16
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)
350,721,070
2,070,664
714,246
352,077,488
17
B. Nuclear Production Plant
18
(320) Land and Land Rights
19
(321) Structures and Improvements
20
(322) Reactor Plant Equipment
21
(323) Turbogenerator Units
22
(324) Accessory Electric Equipment
23
(325) Misc. Power Plant Equipment
24
(326) Asset Retirement Costs for Nuclear Production
25
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26
C. Hydraulic Production Plant
27
(330) Land and Land Rights
28
(331) Structures and Improvements
29
(332) Reservoirs, Dams, and Waterways
30
(333) Water Wheels, Turbines, and Generators
31
(334) Accessory Electric Equipment
32
(335) Misc. Power Plant Equipment
33
(336) Roads, Railroads, and Bridges
34
(337) Asset Retirement Costs for Hydraulic Production
35
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)
36
D. Other Production Plant
37
(340) Land and Land Rights
38
(341) Structures and Improvements
39
(342) Fuel Holders, Products, and Accessories
40
(343) Prime Movers
41
(344) Generators
42
(345) Accessory Electric Equipment
43
(346) Misc. Power Plant Equipment
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)
46
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)
350,721,070
2,070,664
714,246
352,077,488
47
3. Transmission Plant
48
(350) Land and Land Rights
88,165,125
19,046,806
3,944
107,215,875
48.1
(351) Energy Storage Equipment - Transmission
49
(352) Structures and Improvements
26,458,672
31,266,871
258,834
345,971
57,812,680
50
(353) Station Equipment
1,571,251,725
243,376,164
9,862,775
163,586
1,804,601,528
51
(354) Towers and Fixtures
52,731,813
153,905
1,499,864
1,386,731
49,999,123
52
(355) Poles and Fixtures
709,012,095
236,613,093
10,151,637
1,549,245
937,022,796
53
(356) Overhead Conductors and Devices
578,557,288
124,106,182
5,518,560
88,500
697,056,410
54
(357) Underground Conduit
1,474,545
3,466,969
104,737
4,836,777
55
(358) Underground Conductors and Devices
25,504,173
122,047
537,246
25,088,974
56
(359) Roads and Trails
400,347
345,971
54,376
57
(359.1) Asset Retirement Costs for Transmission Plant
58
TOTAL Transmission Plant (Enter Total of lines 49 thru 59)
3,053,555,783
658,152,037
27,933,653
85,628
3,683,688,539
59
4. Distribution Plant
60
(360) Land and Land Rights
15,082,467
8,017,044
1
23,099,512
61
(361) Structures and Improvements
11,649,961
8,352,213
293,358
8,713
19,700,103
62
(362) Station Equipment
478,712,692
81,876,036
7,269,661
553,319,067
63
(363) Energy Storage Equipment – Distribution
64
(364) Poles, Towers, and Fixtures
765,944,187
96,709,572
10,342,645
852,311,114
65
(365) Overhead Conductors and Devices
678,372,476
78,267,950
7,570,487
749,069,939
66
(366) Underground Conduit
74,533,713
6,614,669
72,299
81,076,083
67
(367) Underground Conductors and Devices
320,001,339
30,117,072
1,820,396
348,298,015
68
(368) Line Transformers
666,273,054
53,792,808
20,379,542
699,686,320
69
(369) Services
288,525,299
16,356,218
1,064,560
303,816,957
70
(370) Meters
244,677,552
11,693,106
26,563,543
229,807,115
71
(371) Installations on Customer Premises
69,793,185
1,359,562
769,591
70,383,156
72
(372) Leased Property on Customer Premises
86,896
86,896
73
(373) Street Lighting and Signal Systems
100,444,698
9,777,684
2,627,200
107,595,182
74
(374) Asset Retirement Costs for Distribution Plant
75
TOTAL Distribution Plant (Enter Total of lines 62 thru 76)
3,714,097,519
402,933,934
78,773,282
8,712
4,038,249,459
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
14,944,911
1,250
1
14,943,660
87
(390) Structures and Improvements
116,826,730
218,945,125
2,244,160
333,527,695
88
(391) Office Furniture and Equipment
4,033,045
3,432,097
319,399
16,188
7,161,931
89
(392) Transportation Equipment
283,186
283,186
90
(393) Stores Equipment
1,277,458
117,541
78,579
1,316,420
91
(394) Tools, Shop and Garage Equipment
44,649,539
4,280,614
165,217
85,628
48,850,564
92
(395) Laboratory Equipment
2,366,781
2,366,781
93
(396) Power Operated Equipment
225,097
225,097
94
(397) Communication Equipment
112,228,730
26,235,044
13,515,810
124,947,964
95
(398) Miscellaneous Equipment
4,898,367
268,664
3,216
5,163,815
96
SUBTOTAL (Enter Total of lines 86 thru 95)
301,733,844
253,279,085
16,327,631
101,815
538,787,113
97
(399) Other Tangible Property
98
(399.1) Asset Retirement Costs for General Plant
1,328,665
68,774
24,867
1,372,572
99
TOTAL General Plant (Enter Total of lines 96, 97, and 98)
303,062,509
253,347,859
16,352,498
101,815
540,159,685
100
TOTAL (Accounts 101 and 106)
7,541,654,424
1,353,381,344
136,893,034
8,713
8,758,134,021
101
(102) Electric Plant Purchased (See Instr. 8)
102
(Less) (102) Electric Plant Sold (See Instr. 8)
103
(103) Experimental Plant Unclassified
104
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)
7,541,654,424
1,353,381,344
136,893,034
8,713
8,758,134,021


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
James Rowe Substation, Hidalgo County, TX
(a)
08/01/2010
1,004,575
3
1.9 Acres (5132)
4
Marina 138/12kV Substation, Nueces County, TX
(b)
12/01/2015
272,883
5
1.962 Acres (5195)
6
Pantera 138kV Substation, Hidalgo County, TX
(c)
11/01/2017
287,810
7
6.480 Acres (5213)
8
Valadez 138kV Substation
(d)
04/01/2017
3,023,997
9
(5187)
10
Items under $250,000
352,327
21 Other Property:
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 TOTAL
4,941,592


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Original value: 08/1/2010
(b) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Original value: 12/1/2015
(c) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Original value: 11/1/2017
(d) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseOriginalDate
Original value: 4/1/2017
(e) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Original value: 2021
(f) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Original value: 2019
(g) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Original value: 2023
(h) Concept: ElectricPlantPropertyClassifiedAsHeldForFutureUseExpectedUseInServiceDate
Original value: 2019

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Corpus Christi DDC - Fac Resil
1,557,159
2
Hebbronville SC - (New)
6,101,360
3
Purchase Office for Abilene T
1,078,176
4
Del Rio Service Ctr Relocation
1,232,719
5
Aransas Pass Service Center
5,388,327
6
Purch Land-Kingsville Laydown
2,081,676
7
Corpus Phase 0 D Station
1,664,234
8
Corpus Christi Network Remed
7,316,647
9
Victoria Network Remediation
1,129,317
10
Young - Property Purchase
1,847,854
11
Heines Sub-Purchase Property
1,147,333
12
Closner Sub - D-Station
1,363,286
13
Reading Sub D-Station
1,334,399
14
Stafford Hill D-Station
1,692,575
15
Asherton Sub D-Station
1,048,069
16
McColl Rd Sub - D-Station
3,070,268
17
Heines Sub- Dstation
1,159,246
18
Del Mar Sub - D-station
3,296,846
19
Valadez Sub - D-Station
2,318,564
20
Dustdevil Sub Purchase Propert
3,311,136
21
TCC Distr Pre Eng Parent
7,352,802
22
TCC Distr Pre Eng Parent
1,047,973
23
TCC/Network Monitor Design
2,623,681
24
Maximo Imp - TN - D
1,139,757
25
Maximo Imp - TC - T
2,893,011
26
Maximo Imp - TN - T
1,300,393
27
Maximo Imp - TC - D
3,894,908
28
TNC Next Generation Radio Sys
24,844,820
29
TCC Next Generation Radio Sys
19,419,537
30
Laredo Phase 0 D Station
1,984,756
31
RGV Phase 0 D Station
1,282,341
32
T/TCC/Transmission Work
1,281,427
33
TCC SCADA Upgrades
1,150,439
34
TCC SCADA Upgrades
1,364,574
35
TNC SCADA Upgrades
1,980,089
36
T/TCC/NERC Physical Security
11,308,135
37
T/TNC/NERC Physical Security
1,421,718
38
Trans station Renew-Refurb TCC
30,233,989
39
Trans station Renew-Refurb TNC
14,020,268
40
Trans Line Renew-Refurb TNC
1,092,223
41
T/TC/Telecom Modernization Pro
13,289,636
42
T/TN/Telecom Modernization Pro
1,946,804
43
D/TC/Telecom Modernization Pro
2,434,963
44
TNC Line Rebuild
65,154,303
45
TCC Line Rebuild
3,760,269
46
Fort Stockton to Rio Pecos 69
12,857,001
47
Concho to Miles 69 kV Line Reb
5,756,260
48
Cedar Hill to Miles 69 kV Line
23,222,363
49
Alice to Falfurrias 69 kV Line
12,098,890
50
Turtle Creek to Uvalde 69 kV L
16,968,275
51
Refugio to Tatton 69 kV Line R
20,528,525
52
Calallen to Stadium 69 kV Line
12,670,785
53
Sabinal to Uvalde 69 kV Line R
3,225,515
54
Blessing to Port Lavaca 69 kV
25,792,047
55
Pleasanton to Three Rivers 69
18,295,808
56
Childress to Quanah 69 kV Line
16,912,311
57
Cross Plains to Santa Anna 69
11,529,237
58
Concho to Live Oak 69 kV Line
7,466,991
59
Refugio to Rincon Line Rebuild
14,545,491
60
Lake Pauline to Vernon 69 kV L
4,748,257
61
Yellowjacket to Junction 69 kV
18,643,188
62
Ballinger to Eden 69kV Line Re
9,369,095
63
Friend Ranch to Sonora 69 kV L
14,995,002
64
Gregory to Rincon 69 kV Line R
4,358,221
65
Project Yosemite, Relocate lin
2,794,698
66
TCC Major Eq/Spares-Trans
1,729,111
67
TCC Major Eq/Spares- Distr
9,135,215
68
TNC Major Eq/Spares-Distr
2,516,506
69
Storm Recovery-Harvey
2,717,869
70
Storm Recovery-Harvey- DISTR
6,817,472
71
T/TCC/RTU Reliability
1,305,337
72
Trans station Renew-Refurb TCC
18,742,109
73
Trans station Renew-Refurb TNC
5,313,742
74
Dist station Renew-Refurb TCC
2,041,261
75
Dist Station renew-refurb TNC
1,650,925
76
TCC-T BlnktProj Under $3M
8,082,348
77
TNC-T-BlnktProj Under $3M
1,671,776
78
TCC-D BlnktProj Under $3M
1,550,940
79
T/TC/Capital Blanket - TCC
8,710,009
80
T/TN/Capital Blanket - TNC
1,283,990
81
D/TC/Capital Blanket - TCC
2,600,699
82
Whitepoint Station: Relay
1,961,337
83
TNC Transmission Work
5,196,440
84
TCC Transmission Work
51,317,010
85
TNC Transmission Work
3,337,054
86
TCC Transmission Work
1,282,200
87
Tortuga
3,069,592
88
TCC Transmission Work
1,175,376
89
Uvalde - Campwood 69kV line
4,356,081
90
Rose Rock Interconnection Perm
3,913,301
91
TCC Transmission Work
3,120,727
92
TCC Trans Work
1,610,202
93
Barrilla Improvements
16,455,713
94
Solstice - Bakersfield 345kV
1,711,221
95
Lynx: New 6bk station
8,143,796
96
Rebuild Lynx-Rio Pecos
2,123,879
97
Katz area improvements
8,810,307
98
TNC Transmission Work2
1,113,617
99
TNC Transmission Work
8,815,357
100
TCC Station Work
2,248,614
101
TNC Transmission Work
3,218,039
102
TCC Transmission Work
2,744,318
103
TNC Transmission
3,459,821
104
TNC Transmission
2,996,231
105
TCC Transmission Work
3,458,406
106
AEPTCC Transmission Work
2,169,534
107
AEPTN Trans Pre Eng Parent
7,322,192
108
SS-CI-CPLCo-D GEN PLT
3,754,304
109
TC-Reliability Improvement Blk
7,743,772
110
TC-Service Restoration Blkt
1,330,433
111
TC-Small Capacity Blkt
3,348,242
112
TN-Customer Service Blkt
2,582,428
113
TN-Reliability Improvement Blk
1,737,810
114
AEPTC-D Telecom
3,772,284
115
Other Minor Projects Which is under $1,000,000
72,629,120
43
836,188,274


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2,126,347,537
2,126,347,537
2
Depreciation Provisions for Year, Charged to
3
DepreciationExpenseExcludingAdjustments
(403) Depreciation Expense
247,316,811
247,316,811
4
DepreciationExpenseForAssetRetirementCosts
(403.1) Depreciation Expense for Asset Retirement Costs
2,878,158
2,878,158
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
4,848,186
(a)
4,848,186
10
DepreciationProvision
TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9)
245,346,783
245,346,783
11
Net Charges for Plant Retired:
12
BookCostOfRetiredPlant
Book Cost of Plant Retired
123,773,679
123,773,679
13
CostOfRemovalOfPlant
Cost of Removal
40,617,514
(b)
40,617,514
14
SalvageValueOfRetiredPlant
Salvage (Credit)
9,933,376
(c)
9,933,376
15
NetChargesForRetiredPlant
TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14)
154,457,817
154,457,817
16
OtherAdjustmentsToAccumulatedDepreciation
Other Debit or Cr. Items (Describe, details in footnote):
17.1
16,188
(d)
16,188
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)
2,217,252,691
2,217,252,691
Section B. Balances at End of Year According to Functional Classification
20
AccumulatedDepreciationSteamProduction
Steam Production
218,600,051
218,600,051
21
AccumulatedDepreciationNuclearProduction
Nuclear Production
22
AccumulatedDepreciationHydraulicProductionConventional
Hydraulic Production-Conventional
23
AccumulatedDepreciationHydraulicProductionPumpedStorage
Hydraulic Production-Pumped Storage
24
AccumulatedDepreciationOtherProduction
Other Production
25
AccumulatedDepreciationTransmission
Transmission
560,797,069
560,797,069
26
AccumulatedDepreciationDistribution
Distribution
1,293,435,868
1,293,435,868
27
AccumulatedDepreciationRegionalTransmissionAndMarketOperation
Regional Transmission and Market Operation
28
AccumulatedDepreciationGeneral
General
144,419,703
144,419,703
29
AccumulatedProvisionForDepreciationOfElectricUtilityPlant
TOTAL (Enter Total of lines 20 thru 28)
2,217,252,691
2,217,252,691


FOOTNOTE DATA

(a) Concept: OtherAccounts

Depreciation expense on meters replaced by AMI meters. ($4,848,186)

(b) Concept: CostOfRemovalOfPlant

Includes ($8,941,547) of removal cost in retirement work in progress (RWIP).

(c) Concept: SalvageValueOfRetiredPlant

Includes ($5,697,038) of salvage in retirement work in progress (RWIP).

(d) Concept: OtherAdjustmentsToAccumulatedDepreciation

Investment transferred between accounts. $16,188


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
AEP Texas Central Transition Funding, LLC.
4,499,680
4,499,680
2
SUBTOTAL
4,499,680
4,499,680
3
AEP Texas Central Transition Funding II, LLC.
9,630,093
98,309
9,728,402
4
SUBTOTAL
9,630,093
98,309
9,728,402
5
AEP Texas Central Transition Funding III, LLC.
4,041,016
62,164
4,103,179
6
SUBTOTAL
4,041,016
62,164
4,103,179
7
AEP Texas North Generation Company, LLC
7,320,453
215,082
7,105,371
8
SUBTOTAL
7,320,453
215,082
7,105,371
42
Total Cost of Account 123.1 $
Total
25,491,242
54,609
25,436,632


FOOTNOTE DATA

(a) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 02/2002
(b) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 10/2006
(c) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 02/2012
(d) Concept: DateOfAcquisitionInvestmentsInSubsidiaryCompanies
Original value: 08/2006

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
3,438,722
8,667,188
Electric
2
Fuel Stock Expenses Undistributed (Account 152)
142,942
158,854
Electric
3
Residuals and Extracted Products (Account 153)
4
Plant Materials and Operating Supplies (Account 154)
5
Assigned to - Construction (Estimated)
44,244,907
45,607,378
Electric
6
Assigned to - Operations and Maintenance
7
Production Plant (Estimated)
3,850,140
3,875,783
Electric
8
Transmission Plant (Estimated)
1,760,493
981,670
Electric
9
Distribution Plant (Estimated)
2,059,391
2,161,107
Electric
10
Regional Transmission and Market Operation Plant (Estimated)
11
Assigned to - Other (provide details in footnote)
(a)
129,807
170,397
Electric
12
TOTAL Account 154 (Enter Total of lines 5 thru 11)
52,044,738
52,796,335
Electric
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)
17
18
19
20
TOTAL Materials and Supplies
55,626,402
61,622,377


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PlantMaterialsAndOperatingSuppliesOther

This footnote applies to both current and prior year.

 

Assigned to - Other: Includes Customer Accounts and Administrative and General Expenses.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
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
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
30
30
30
30
2,996
3,116
37
Add: Withheld by EPA
30
30
38
Deduct: Returned by EPA
39
Cost of Sales
30
15
45
40
Balance-End of Year
30
30
30
3,011
3,101
41
42
Sales
43
Net Sales Proceeds (Assoc. Co.)
1
1
44
Net Sales Proceeds (Other)
1
1
45
Gains
46
Losses


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
7,477
7,477
2
3
Acquired During Year:
4
Issued (Less Withheld Allow)
7,477
7,477
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
20.2
21
Cost of Sales/Transfers:
22
23
24
25
26
27
28
Total
29
Balance-End of Year
14,954
14,954
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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
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
20 TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Electric Reliability Council of
3
(a)
Texas (ERCOT) - 11AEPSC001
14,869
4
11INR0054
55,017
80,000
5
11INR0062
126,961
6
11INR0062(a1)
5,716
60,000
7
12INR0045
37,306
8
13INR0055
256
9
14INR0013
1,701
10
14INR0040
11,862
11
14INR0041
162
12
15INR0021
28,150
13
15INR0034
624
14
15INR0045
768
15
15INR0054
40,485
16
15INR0059
8,703
17
15INR0061
256
18
15INR0069
24,665
19
16INR0048
256
20
16INR0052
256
21
16INR0086
1,537
22
16INR0101
256
23
16INR0105
256
24
17INR0031
1,024
25
17INR0035
39,162
80,000
26
17INR0045
2,891
27
17INR0052
1,459
28
18INR0014
22,165
80,000
29
18INR0027
801
30
18INR0035
6,770
31
18INR0058
12,100
32
18INR0059
11,906
80,000
33
18INR0060
4,899
34
18INR0061
6,937
35
18INR0079
12,564
125,000
36
19INR0006
1,832
37
19INR0014
10,002
38
19INR0022
12,634
39
19INR0035
65,000
40
19INR0045
5,525
41
19INR0049
65,000
42
19INR0057
3,744
65,000
43
19INR0073
4,995
44
19INR0074
10,789
145,000
45
19INR0108
4,998
145,000
46
19INR0111
65,000
47
19INR0122
22,558
145,000
48
19INR0138
65,000
49
19INR0150
65,000
50
19INR0171
5,578
65,000
51
19INR0177
65,000
52
19INR0113
256
62,500
53
20INR0012
256
65,000
54
20INR0013
807
65,000
55
20INR0014
276
65,000
56
20INR0016
256
65,000
57
20INR0036
65,000
58
20INR0042
21,076
65,000
59
20INR0053
65,000
60
20INR0054
16,445
70,000
61
20INR0055
65,000
20
Total
21
Generation Studies
39
Total
40 Grand Total


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DescriptionOfStudyPerformed

 

Respondent is unable to expand on the description due to Electric Reliability Council of

Texas (ERCOT) disclosure limitations when studies are in process.

 


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
SFAS 109 Deferred FIT
14,749,162
3,858,531
18,607,693
2
SFAS 109 Deferred SIT
27,161,048
68,011
27,229,059
3
SFAS 106 Medicare Subsidy (Amortization
4
period Jan 2013 - Dec 2024)
4,873,828
696,261
4,177,567
5
Under-recovery of Energy Efficiency
6
Program Expenses - as approved by PUCT
7
Docket (updated annually)
3,685,219
6,342,992
7,578,177
2,450,034
8
Various Rate Case Expenses pending
9
future PUCT (Public Utility Commission of Texas)
10
approval for collection from customers.
149,525
11,123
160,648
11
SFAS 158 Employers' Accounting for Defined Benefit
12
Pension and Other Postretirement Plans
151,160,454
33,366,488
7,659,404
176,867,538
13
Deferred Equity Return and other Competition
14
Transition Charge (CTC) items relating to TCC's
15
Securitization filing - Amortized over 14 years
16
beginning October 2006. Various Dockets
17
including TCC's Securitization Docket #32475
18
and CTC Docket #32758
21,694,308
23,643,420
33,014,322
12,323,406
19
Reserve for Catastrophe for storm recovery.
20
Currently funded at an annual rate of
21
$1.3M per yar. Updated last on
22
PUCT Docket #33309.
123,298,991
30,450,600
1,300,000
152,449,591
23
Advanced Metering Systems O&M expenses to be
24
recovered over 11 years beginning in 2010
25
as approved in PUCT Docket #36928
629,150
209,616
419,534
26
Advanced Metering Systems Existing Meter Investment
27
of "old meters retired" and replaced by "Advanced
28
Meters" as approved in PUCT Docket #36928
44,926,765
4,848,186
40,078,579
29
Under-recovery of Transmission Cost
30
Recovery Factor - as approved by
31
PUCT Dockey (updated semiannually)
9,460,892
12,792,059
20,527,562
1,725,389
32
Under-recovery of Advanced Metering Systems
33
Expense as approved in PUCT Docket #36928
32,863,914
12,044,297
44,908,211
34
Restructuring Costs - Unamortized Loss on
35
Reacquired Long-Term Debt - Amortized over
36
15 years beginning July 2002
37
Docket # 22352 (Central)
89,118
70,880
18,238
38
Unrealized Gain/Loss on Forward
39
Commitments
728,659
728,659
44
TOTAL
434,742,374
123,306,180
75,904,408
482,144,146


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Associated Business Development
517,186
11,422,607
10,878,540
1,061,253
2
Unamortized Credit Line Fees
3
Amortization period through
4
June 2022
524,407
510,250
202,023
832,634
5
Deferred Lease Assets
347,850
1,409,910
1,185,640
572,120
6
Death Benefits Paid Related to
7
CSW's Memorial Paired Program
8
Minor Items < $100,000 or 1%
12,155
11,222
21,733
1,644
47
Miscellaneous Work in Progress
48
Deferred Regulatroy Comm. Expenses (See pages 350 - 351)
49
TOTAL
1,401,598
2,467,651


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Deferred Revenues - Oklaunion Lease
18,181,032
4,637,124
3
Accrd Book ARO Expense - SFAS 143
9,147,808
5,743,220
4
O/U Recovery Securitization Revenue
16,113,714
9,652,252
5
Defd Revenues - Defd Equity Return - SEC
21,142,303
7,777,131
6
Securitization Defd Equity Income - Long Term
18,882,156
9,804,914
7
8
7
Other
20,635,536
17,424,812
8 TOTAL Electric (Enter Total of lines 2 thru 7)
62,831,477
55,039,453
9
Other (Specify)
10
11
12
13
14
15
Other
16 TOTAL Gas (Enter Total of lines 10 thru 15)
17 Other (Specify)
18 TOTAL (Acct 190) (Total of lines 8, 16 and 17)
220,717,834
207,916,285
Notes
Footnote Page 234, Line 17 - Columns (b) & (c) Beg of Year End of Year Accumulated Deferred Income Taxes - Federal - Hdg-CF-Int Rate 1,450,350 1,169,637 Non Utility Items - 190.2 1,530,348 (401,711) SFAS 109 - Regulatory Assets - 190.3 & 190.4 152,269,223 149,251,923 Accumulated Deferred Income Taxes - Federal - Pension - OCI 2,636,436 2,850,984 ------------- -------------- Total Other 157,886,357 152,876,832


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
6
Preferred Stock (Account 204)
7
8
9
10
Total
1
Capital Stock (Accounts 201 and 204) - Data Conversion
2
3
4
5
Total


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Donations Received from Stockholders (Account 208)
19.2
IncreasesDecreasesInOtherPaidInCapital
Beginning Balance
1,058,164,804
19.3
IncreasesDecreasesInOtherPaidInCapital
Capital Contribution from Parent
200,000,000
19.4
IncreasesDecreasesInOtherPaidInCapital
Subtotal - Account 208
1,258,164,804
19.5
IncreasesDecreasesInOtherPaidInCapital
Reduction In Par or Stated Value of Capital Stock (Account 209) - None
19.6
IncreasesDecreasesInOtherPaidInCapital
Gain on Resale or Cancellation of Reaquired Capital Stock (Acct 210)
19.7
IncreasesDecreasesInOtherPaidInCapital
Reacquired Capital StocK (Account 210)
13,116
19.8
IncreasesDecreasesInOtherPaidInCapital
Reacquired Preferred Stock (Account 210)
230,126
19.9
IncreasesDecreasesInOtherPaidInCapital
Subtotal - Account 210
217,010
19.10
IncreasesDecreasesInOtherPaidInCapital
Miscellaneous Paid-In Capital (Account 211)
20
OtherPaidInCapitalDetail
Ending Balance Amount
40
OtherPaidInCapital
Total
1,257,947,794


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
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
3,114,186,630
Long Term Debt (Historical Data)
1
Total Account 221
2
Total Account 222
3
Account 223 - Advances from Associated Companies - None
4
Account 224 - Other Long-Term Debt
5
Pollution Control Bonds:
6
Series 1996, 4.45% - (Red River) (Issued 06-2007)
6,330,000
95,403
(l)
06/07/2007
(ap)
06/01/2020
(bt)
06/07/2007
(cx)
06/01/2020
6,330,000
281,685
7
(a)
Series 1996, Matagorda Remarketing, 1.75% (Issued 08-21-2017)
60,000,000
439,654
(m)
08/21/2017
(aq)
05/01/2030
(bu)
08/21/2017
(cy)
09/01/2020
60,000,000
1,050,000
8
1,200,000
9
(b)
Series 2001A, 6.3% - (Matagorda)
100,635,000
845,451
(n)
07/01/2009
(ar)
11/01/2029
(bv)
07/01/2009
(cz)
11/01/2029
100,635,000
6,340,005
10
(c)
Series 2005A, 4.4% - (Matagorda)
111,700,000
1,277,849
(o)
12/06/2006
(as)
05/01/2030
(bw)
03/16/2005
(da)
05/01/2030
111,700,000
4,914,800
11
(d)
Series 2005B, 4.55% - (Matagorda)
50,000,000
552,686
(p)
12/06/2006
(at)
05/01/2030
(bx)
03/16/2005
(db)
05/01/2030
50,000,000
2,275,000
12
(e)
Series 2008 - 1&2, Matagorda Remarketing, 4.0% (Issued 6-3-2013)
120,265,000
776,485
(q)
06/03/2013
(au)
06/01/2030
(by)
06/03/2013
(dc)
06/01/2030
120,265,000
4,810,600
13
Red River, 4.45% (Issued 06-2007)
44,310,000
673,131
(r)
06/07/2007
(av)
06/01/2020
(bz)
06/07/2007
(dd)
06/01/2020
44,310,000
1,971,795
14
15
Private Placement Notes:
16
Series B, 6.76%
1,600,000
(j)
457,765
(s)
04/01/2008
(aw)
04/01/2038
(ca)
04/01/2008
(de)
04/01/2038
1,600,000
108,160
17
Series B, 6.76%
12,700,000
(t)
04/01/2008
(ax)
04/01/2038
(cb)
04/01/2008
(df)
04/01/2038
12,700,000
858,520
18
Series B, 6.76%
13,700,000
(u)
04/01/2008
(ay)
04/01/2038
(cc)
04/01/2008
(dg)
04/01/2038
13,700,000
926,120
19
Series B, 6.76%
35,000,000
(v)
04/01/2008
(az)
04/01/2038
(cd)
04/01/2008
(dh)
04/01/2038
35,000,000
2,366,000
20
Series B, 6.76%
7,000,000
(w)
04/01/2008
(ba)
04/01/2038
(ce)
04/01/2008
(di)
04/01/2038
7,000,000
473,200
21
(g)
Series A, 5.89%
30,000,000
196,185
(x)
04/01/2008
(bb)
04/02/2018
(cf)
04/01/2008
(dj)
04/02/2018
441,750
22
Other Long-Term Debt:
23
Texas Local Revolving Credit Facility
125,000,000
495,556
(y)
07/25/2016
(bc)
07/31/2019
(cg)
08/01/2016
(dk)
07/31/2019
125,000,000
4,482,639
24
Texas Local Revolving Credit Facility
75,000,000
285,761
(z)
07/25/2016
(bd)
07/31/2019
(ch)
08/01/2016
(dl)
07/31/2019
75,000,000
2,689,583
25
(h)
Goodfellow Air Force Base - 4.5%
946,630
(aa)
12/01/2009
(be)
11/01/2059
(ci)
12/01/2009
(dm)
11/01/2059
946,630
42,791
26
Senior Unsecured Notes:
27
Series C, 3.09%
125,000,000
597,741
(ab)
02/28/2013
(bf)
02/28/2023
(cj)
02/28/2013
(dn)
02/28/2023
125,000,000
3,862,500
28
Series C - Financial Hedges
1,336,728
29
Series D, 4.48%
75,000,000
358,644
(ac)
02/27/2013
(bg)
02/27/2043
(ck)
02/27/2013
(do)
02/27/2043
75,000,000
3,360,000
30
Series E, 3.27%
25,000,000
126,464
(ad)
09/30/2015
(bh)
09/30/2022
(cl)
09/30/2015
(dp)
09/30/2022
25,000,000
817,500
31
Series F, 3.75%
50,000,000
252,928
(ae)
09/30/2015
(bi)
09/30/2025
(cm)
09/30/2015
(dq)
09/30/2025
50,000,000
1,875,000
32
Series G, 4.71%
50,000,000
252,928
(af)
12/15/2015
(bj)
12/15/2035
(cn)
12/15/2015
(dr)
12/15/2035
50,000,000
2,355,000
33
Series E (formerly B) 6.65% Notes
275,000,000
2,504,241
(ag)
02/18/2003
(bk)
02/15/2033
(co)
03/01/2003
(ds)
02/15/2033
275,000,000
18,287,500
34
1,342,000
35
Series A, 2.61%
50,000,000
(ah)
04/30/2014
(bl)
04/30/2019
(cp)
04/30/2014
(dt)
04/30/2019
50,000,000
1,305,000
36
Series B, 3.81%
50,000,000
(ai)
04/30/2014
(bm)
04/30/2026
(cq)
04/30/2014
(du)
04/30/2026
50,000,000
1,905,000
37
Series C, 4.67%
100,000,000
(aj)
04/30/2014
(bn)
04/30/2044
(cr)
04/30/2014
(dv)
04/30/2044
100,000,000
4,670,000
38
Series D, 4.77%
100,000,000
(k)
1,454,317
(ak)
10/30/2014
(bo)
10/30/2044
(cs)
10/30/2014
(dw)
10/30/2044
100,000,000
4,770,000
39
Series G, 3.85%
250,000,000
1,864,770
(al)
09/18/2015
(bp)
10/01/2025
(ct)
09/18/2015
(dx)
10/01/2025
250,000,000
9,625,000
40
2,447,500
41
Series A, 2.4%
400,000,000
3,047,760
(am)
09/22/2017
(bq)
10/01/2022
(cu)
09/22/2017
(dy)
10/01/2022
400,000,000
9,600,000
42
(FERC Authority ES16-47-000)
696,000
43
Series B, 3.8%
300,000,000
3,129,449
(an)
09/22/2017
(br)
10/01/2047
(cv)
09/22/2017
(dz)
10/01/2047
300,000,000
11,400,000
44
(FERC Authority ES16-47-000)
3,450,000
45
(i)
Series E, 3.95%
500,000,000
3,922,721
(ao)
05/17/2018
(bs)
06/01/2028
(cw)
05/17/2018
(ea)
06/01/2028
500,000,000
12,288,890
46
(FERC Authority ES18-22-000)
1,650,000
33 TOTAL
3,144,186,630
31,993,389
3,114,186,630
121,490,766


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: ClassAndSeriesOfObligationCouponRateDescription

In August 2017, AEP Texas remarketed its Series 1996 Matagorda Pollution Control Revenue Bonds (PCRBs) from 5.20% to 1.75% fixed rate. Column (C) amount includes remarketing issuance costs. There was $992,572 of unamortized issuance costs and discount when remarketed.

(b) Concept: ClassAndSeriesOfObligationCouponRateDescription

In July 2009, TCC remarketed its Series 2001A Matagorda Pollution Control Bonds (PCRBs) from 4.55% to 6.30% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(c) Concept: ClassAndSeriesOfObligationCouponRateDescription

In December 2006, TCC remarketed its Series 2005A Matagorda Pollution Control Bonds (PCRBs) from a vraiable rate to 4.40% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(d) Concept: ClassAndSeriesOfObligationCouponRateDescription

In December 2006, TCC remarketed its Series 2005B Matagorda Pollution Control Bonds (PCRBs) from a variable rate to 4.55% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(e) Concept: ClassAndSeriesOfObligationCouponRateDescription

In July 2013, TCC remarketed its Series 2008 Matagorda Pollution Control Bonds (PCRBs) from a variable weekly rate to a 4.00% fixed rate. Column ( C ) amount includes remarketing issuance costs.

(f) Concept: ClassAndSeriesOfObligationCouponRateDescription

The Series 2008, 5.625% (Guadalupe/Blanco) was retired on 10/2/2017. There were no unamortized amounts related to this issuance.

(g) Concept: ClassAndSeriesOfObligationCouponRateDescription

The Series A, 5.89% was retired on 4/01/2018. There were no unamortized amounts related to this issuance.

(h) Concept: ClassAndSeriesOfObligationCouponRateDescription

This is long term debt related to AEP Texas North Company's purchase of the Goodfellow Air Force Base Electric Distribution System, to be paid over a 50 year period.

(i) Concept: ClassAndSeriesOfObligationCouponRateDescription

In May 2018, new Issuance for AEP Texas Series E Unsecured Notes 3.95% for $500,000,000 with maturity date June 2028.

(j) Concept: LongTermDebtIssuanceExpensePremiumOrDiscount

The issuance expense amount of $457,765 is the total expense amount for all five Series B Private Placement Notes. The total principal for the five Series B placement notes total $70,000,000. The issuance expenses are not kept separate for each individual private placement holder.

(k) Concept: LongTermDebtIssuanceExpensePremiumOrDiscount

The "Issuance Costs" reported in Column ( C ) for Series D Unsecured Notes, issued in 2014, are actually for "all four Series Notes issued in 2014" (including Series A 2.61%, Series B 3.81%, Series C 4.67%, and Series D 4.77%).

(l) Concept: NominalDateOfIssue
Original value: 06/07/2007
(m) Concept: NominalDateOfIssue
Original value: 08/21/2017
(n) Concept: NominalDateOfIssue
Original value: 07/01/2009
(o) Concept: NominalDateOfIssue
Original value: 12/06/2006
(p) Concept: NominalDateOfIssue
Original value: 12/06/2006
(q) Concept: NominalDateOfIssue
Original value: 06/03/2013
(r) Concept: NominalDateOfIssue
Original value: 06/07/2007
(s) Concept: NominalDateOfIssue
Original value: 04/01/2008
(t) Concept: NominalDateOfIssue
Original value: 04/01/2008
(u) Concept: NominalDateOfIssue
Original value: 04/01/2008
(v) Concept: NominalDateOfIssue
Original value: 04/01/2008
(w) Concept: NominalDateOfIssue
Original value: 04/01/2008
(x) Concept: NominalDateOfIssue
Original value: 04/01/2008
(y) Concept: NominalDateOfIssue
Original value: 07/25/2016
(z) Concept: NominalDateOfIssue
Original value: 07/25/2016
(aa) Concept: NominalDateOfIssue
Original value: 12/01/2009
(ab) Concept: NominalDateOfIssue
Original value: 02/28/2013
(ac) Concept: NominalDateOfIssue
Original value: 02/27/2013
(ad) Concept: NominalDateOfIssue
Original value: 09/30/2015
(ae) Concept: NominalDateOfIssue
Original value: 09/30/2015
(af) Concept: NominalDateOfIssue
Original value: 12/15/2015
(ag) Concept: NominalDateOfIssue
Original value: 02/18/2003
(ah) Concept: NominalDateOfIssue
Original value: 04/30/2014
(ai) Concept: NominalDateOfIssue
Original value: 04/30/2014
(aj) Concept: NominalDateOfIssue
Original value: 04/30/2014
(ak) Concept: NominalDateOfIssue
Original value: 10/30/2014
(al) Concept: NominalDateOfIssue
Original value: 09/18/2015
(am) Concept: NominalDateOfIssue
Original value: 09/22/2017
(an) Concept: NominalDateOfIssue
Original value: 09/22/2017
(ao) Concept: NominalDateOfIssue
Original value: 05/17/2018
(ap) Concept: DateOfMaturity
Original value: 06/01/2020
(aq) Concept: DateOfMaturity
Original value: 05/01/2030
(ar) Concept: DateOfMaturity
Original value: 11/01/2029
(as) Concept: DateOfMaturity
Original value: 05/01/2030
(at) Concept: DateOfMaturity
Original value: 05/01/2030
(au) Concept: DateOfMaturity
Original value: 06/01/2030
(av) Concept: DateOfMaturity
Original value: 06/01/2020
(aw) Concept: DateOfMaturity
Original value: 04/01/2038
(ax) Concept: DateOfMaturity
Original value: 04/01/2038
(ay) Concept: DateOfMaturity
Original value: 04/01/2038
(az) Concept: DateOfMaturity
Original value: 04/01/2038
(ba) Concept: DateOfMaturity
Original value: 04/01/2038
(bb) Concept: DateOfMaturity
Original value: 04/02/2018
(bc) Concept: DateOfMaturity
Original value: 07/31/2019
(bd) Concept: DateOfMaturity
Original value: 07/31/2019
(be) Concept: DateOfMaturity
Original value: 11/01/2059
(bf) Concept: DateOfMaturity
Original value: 02/28/2023
(bg) Concept: DateOfMaturity
Original value: 02/27/2043
(bh) Concept: DateOfMaturity
Original value: 09/30/2022
(bi) Concept: DateOfMaturity
Original value: 09/30/2025
(bj) Concept: DateOfMaturity
Original value: 12/15/2035
(bk) Concept: DateOfMaturity
Original value: 02/15/2033
(bl) Concept: DateOfMaturity
Original value: 04/30/2019
(bm) Concept: DateOfMaturity
Original value: 04/30/2026
(bn) Concept: DateOfMaturity
Original value: 04/30/2044
(bo) Concept: DateOfMaturity
Original value: 10/30/2044
(bp) Concept: DateOfMaturity
Original value: 10/01/2025
(bq) Concept: DateOfMaturity
Original value: 10/01/2022
(br) Concept: DateOfMaturity
Original value: 10/01/2047
(bs) Concept: DateOfMaturity
Original value: 06/01/2028
(bt) Concept: AmortizationPeriodStartDate
Original value: 06/07/2007
(bu) Concept: AmortizationPeriodStartDate
Original value: 08/21/2017
(bv) Concept: AmortizationPeriodStartDate
Original value: 07/01/2009
(bw) Concept: AmortizationPeriodStartDate
Original value: 03/16/2005
(bx) Concept: AmortizationPeriodStartDate
Original value: 03/16/2005
(by) Concept: AmortizationPeriodStartDate
Original value: 06/03/2013
(bz) Concept: AmortizationPeriodStartDate
Original value: 06/07/2007
(ca) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(cb) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(cc) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(cd) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(ce) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(cf) Concept: AmortizationPeriodStartDate
Original value: 04/01/2008
(cg) Concept: AmortizationPeriodStartDate
Original value: 08/01/2016
(ch) Concept: AmortizationPeriodStartDate
Original value: 08/01/2016
(ci) Concept: AmortizationPeriodStartDate
Original value: 12/01/2009
(cj) Concept: AmortizationPeriodStartDate
Original value: 02/28/2013
(ck) Concept: AmortizationPeriodStartDate
Original value: 02/27/2013
(cl) Concept: AmortizationPeriodStartDate
Original value: 09/30/2015
(cm) Concept: AmortizationPeriodStartDate
Original value: 09/30/2015
(cn) Concept: AmortizationPeriodStartDate
Original value: 12/15/2015
(co) Concept: AmortizationPeriodStartDate
Original value: 03/01/2003
(cp) Concept: AmortizationPeriodStartDate
Original value: 04/30/2014
(cq) Concept: AmortizationPeriodStartDate
Original value: 04/30/2014
(cr) Concept: AmortizationPeriodStartDate
Original value: 04/30/2014
(cs) Concept: AmortizationPeriodStartDate
Original value: 10/30/2014
(ct) Concept: AmortizationPeriodStartDate
Original value: 09/18/2015
(cu) Concept: AmortizationPeriodStartDate
Original value: 09/22/2017
(cv) Concept: AmortizationPeriodStartDate
Original value: 09/22/2017
(cw) Concept: AmortizationPeriodStartDate
Original value: 05/17/2018
(cx) Concept: AmortizationPeriodEndDate
Original value: 06/01/2020
(cy) Concept: AmortizationPeriodEndDate
Original value: 09/01/2020
(cz) Concept: AmortizationPeriodEndDate
Original value: 11/01/2029
(da) Concept: AmortizationPeriodEndDate
Original value: 05/01/2030
(db) Concept: AmortizationPeriodEndDate
Original value: 05/01/2030
(dc) Concept: AmortizationPeriodEndDate
Original value: 06/01/2030
(dd) Concept: AmortizationPeriodEndDate
Original value: 06/01/2020
(de) Concept: AmortizationPeriodEndDate
Original value: 04/01/2038
(df) Concept: AmortizationPeriodEndDate
Original value: 04/01/2038
(dg) Concept: AmortizationPeriodEndDate
Original value: 04/01/2038
(dh) Concept: AmortizationPeriodEndDate
Original value: 04/01/2038
(di) Concept: AmortizationPeriodEndDate
Original value: 04/01/2038
(dj) Concept: AmortizationPeriodEndDate
Original value: 04/02/2018
(dk) Concept: AmortizationPeriodEndDate
Original value: 07/31/2019
(dl) Concept: AmortizationPeriodEndDate
Original value: 07/31/2019
(dm) Concept: AmortizationPeriodEndDate
Original value: 11/01/2059
(dn) Concept: AmortizationPeriodEndDate
Original value: 02/28/2023
(do) Concept: AmortizationPeriodEndDate
Original value: 02/27/2043
(dp) Concept: AmortizationPeriodEndDate
Original value: 09/30/2022
(dq) Concept: AmortizationPeriodEndDate
Original value: 09/30/2025
(dr) Concept: AmortizationPeriodEndDate
Original value: 12/15/2035
(ds) Concept: AmortizationPeriodEndDate
Original value: 02/15/2033
(dt) Concept: AmortizationPeriodEndDate
Original value: 04/30/2019
(du) Concept: AmortizationPeriodEndDate
Original value: 04/30/2026
(dv) Concept: AmortizationPeriodEndDate
Original value: 04/30/2044
(dw) Concept: AmortizationPeriodEndDate
Original value: 10/30/2044
(dx) Concept: AmortizationPeriodEndDate
Original value: 10/01/2025
(dy) Concept: AmortizationPeriodEndDate
Original value: 10/01/2022
(dz) Concept: AmortizationPeriodEndDate
Original value: 10/01/2047
(ea) Concept: AmortizationPeriodEndDate
Original value: 06/01/2028

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
211,345,402
2
Reconciling Items for the Year
3
4
Taxable Income Not Reported on Books
5
6
7
8
9
Deductions Recorded on Books Not Deducted for Return
10
11
12
13
14
Income Recorded on Books Not Included in Return
15
16
17
18
19
Deductions on Return Not Charged Against Book Income
20
21
22
23
24
25
26
27
Federal Tax Net Income
214,924,796
28
Show Computation of Tax:
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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 Taxes
2
Income Taxes
40,286,768
1,123,955
2,667,773
44,078,496
3,470,591
2,346,636
3
Federal Fin 48
380,499
380,499
380,499
4
IRS Audit
433,656
37,779,778
(a)
38,213,434
38,213,434
433,656
5
FICA - 2018
1,024,993
11,181,987
10,730,519
1,476,460
5,872,645
5,309,342
6
Unemployment - 2018
28,259
74,317
69,039
33,537
41,111
33,206
7
State of Texas
8
TX Income Taxes - 2015
9
TX Income Taxes - 2016
10
TX Income Taxes - 2017
4,581,953
1,202,037
3,379,916
1,202,037
11
TX Income Taxes - 2017
2,968,179
2,968,179
2,968,179
12
Unemployment - TX 2018
54,887
154,920
157,684
52,123
53,453
101,467
13
TX Local Franchise - 2017
3,932,089
56,120
3,875,969
56,120
14
TX Local Franchise - 2018
51,643,875
47,790,236
3,853,639
51,587,755
56,120
15
TX Sales\Use Tax 2016
3,938,937
3,938,937
194,747
3,744,190
16
TX Sales\Use Tax 2017
15,114,198
1,675,009
13,439,189
1,675,009
17
TX Sales\Use Tax 2018
31,700,036
27,650,926
4,049,110
7,824
31,692,212
18
TX Use Tax-Audit Provisions
137,500
137,500
137,500
19
Texas Ad Valorem - 2013
136
136
136
20
Texas Ad Valorem - 2014
386
386
386
21
Texas Ad Valorem - 2015
137
137
137
22
Texas Ad Valorem - 2016
2,296
2,296
2,296
23
Texas Ad Valorem - 2017
51,712,770
377,875
51,334,895
377,875
24
Texas Ad Valorem - 2018
77,275,850
15,528,542
61,747,308
73,340,860
3,934,990
25
Texas Lsd PP Taxes - 2017
590,014
459,532
1,043,541
6,005
470,185
10,653
26
Texas Lsd PP Taxes - 2018
1,434,086
121,591
1,312,495
1,434,086
27
TX Gross Margins - 2015
28
TX Gross Margins - 2016
29
TX Gross Margins - 2017
30
State of Oklahoma
31
State Registration Fee
26
26
26
32
Unemployment - OK 2018
27
27
33
State of Delaware
34
State Registration Fee
825
825
1,125
300
35
Ohio State Taxes
36
OH CAT- 2015
37
OH CAT- 2017
2
2
2
38
OH CAT- 2018
8
8
8
39
Other
40
State Income Tax - FIN48
1,566,650
268,641
1,835,291
4
4
40
TOTAL
35,376,376
29,585,069


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TaxAdjustments

This adjustment is for FIN 48 deferred taxes in the payable account that had an offset to accounts 410.1 and 411.1 in the amount of -$38,213,434


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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%
12,305,570
1,462,070
10,843,500
8 TOTAL
12,305,570
1,462,070
10,843,500
9
Other (List separately and show 3%, 4%, 7%, 10% and TOTAL)
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48 TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Pole Attachments
1,337,097
3,943,702
3,948,068
1,341,463
2
Power Purchase and
3
Sale Agreement Deferral
51,945,805
5,586,200
46,359,605
4
Security Deposits
11,328,745
1,071,109
8,613,318
18,870,954
5
Deferred Equity Income relating to
6
Supreme Court of Texas July 2011
7
Reversal of 2006 Capacity Auction
8
True-up Disallowance (PUCT
9
Docket #39722)
53,949,017
7,258,952
46,690,065
10
Contributions in Aid
11
of Construction
7,535,734
16,673,375
24,209,109
12
Associated Business Development
1,794,325
1,794,325
3,590,785
3,590,785
13
Environmental Liabilities
530,225
267,347
262,878
14
Texas Reliability Entity -
15
Audit Assessment
360,000
516,500
876,500
16
Asbestos Litigation Contingency
1,250,000
1,250,000
17
Minor Items < $100,000
129,562
63,470
193,032
47
TOTAL
130,160,510
19,921,635
33,405,516
143,644,391


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Other
5.2
Other
8
TOTAL Electric (Enter Total of lines 3 thru 7)
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
16.1
Other
16.2
Other
17
TOTAL (Acct 281) (Total of 8, 15 and 16)
18
Classification of TOTAL
19
Federal Income Tax
20
State Income Tax
21
Local Income Tax


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
1,248,004,017
1,529,937,353
1,449,951,729
1,327,989,641
3
Gas
4
Other (Specify)
5
Total (Total of lines 2 thru 4)
1,248,004,017
1,529,937,353
1,449,951,729
1,327,989,641
6
Regulatory Assets - SFAS109
487,132,667
1,059,266,200
1,063,085,732
483,313,135
9
TOTAL Account 282 (Total of Lines 5 thru 8)
760,871,350
1,529,937,353
1,449,951,729
1,059,266,200
1,063,085,732
844,676,506
10
Classification of TOTAL
11
Federal Income Tax
760,871,350
1,529,937,353
1,449,951,729
1,059,266,200
1,063,085,732
844,676,506
12
State Income Tax
13
Local Income Tax


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Accrued BK Pension Expense
60,565,308
469,311
25,984,133
35,050,486
4
Provision for Damages
43,154,647
7,064,394
18,204,627
32,014,414
5
Defd Tax Gain Securitized Reg
323,222,870
179,697,333
143,525,537
6
Reg Asset Advanced Metering
27,446,941
9,951,188
19,462,801
17,935,328
7
Reg Asset-Loss on Reacquired D
2,652,003
1,386,980
1,265,023
8
Other
134,891,516
262,666,209
96,519,775
31,254,918
9 TOTAL Electric (Total of lines 3 thru 8)
322,150,253
280,151,102
341,255,649
261,045,706
10
Gas
11
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16)
18 TOTAL Other
(a)
12,958,335
11,592,108
18,525,115
128,727,832
138,219,280
15,516,776
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)
335,108,588
291,743,210
359,780,764
128,727,832
138,219,280
276,562,482
20
Classification of TOTAL
21
Federal Income Tax
307,642,917
291,719,405
359,637,919
125,699,936
135,123,373
249,147,840
22
State Income Tax
27,465,671
23,805
142,845
3,027,896
3,095,907
27,414,642
23
Local Income Tax
NOTES


FOOTNOTE DATA

(a) Concept: AccumulatedDeferredIncomeTaxesOther

Description Beg Bal DR 410 CR 411 Debits Credits End Bal

 

Non-Utility 17,388,163 11,592,108 18,525,115 0 0 10,455,156

SFAS 109 -4,429,828 0 0 128,727,832 138,219,280 5,061,620

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

Total 12,958,335 11,592,108 18,525,115 128,727,832 138,219,280 15,516,776


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
SFAS 109 Deferred FIT
685,741,928
12,454,362
673,287,566
2
Earnings Subject to Refund under
3
State of Texas Restructuring Legislation
4
Amortization @ 3.361% or approximately 30 years
5
per Docket No. 22354
6,821,679
496,012
6,325,667
6
FERC System Integration Agreement (SIA)
7
Refund to be applied as a reduction to
8
Advanced Metering System
9
Investment - PUCT Docket #36924 and 36928
12,749,261
4,249,751
8,499,510
10
Other Comprehensive Income (OCI) Excess
11
Deferred Income Tax Adjustment - for
12
2018 Tax Reform Act
966,900
1,019,522
52,622
13
Unrealized Gain/Loss on Forward
14
Commitments
511,815
511,815
41 TOTAL
704,857,783
17,711,940
1,019,522
688,165,365


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
3
CommercialAndIndustrialSalesAbstract
(442) Commercial and Industrial Sales
4
CommercialSalesAbstract
Small (or Comm.) (See Instr. 4)
5
IndustrialSalesAbstract
Large (or Ind.) (See Instr. 4)
6
PublicStreetAndHighwayLightingAbstract
(444) Public Street and Highway Lighting
7
OtherSalesToPublicAuthoritiesAbstract
(445) Other Sales to Public Authorities
8
SalesToRailroadsAndRailwaysAbstract
(446) Sales to Railroads and Railways
9
InterdepartmentalSalesAbstract
(448) Interdepartmental Sales
10
SalesToUltimateConsumersAbstract
TOTAL Sales to Ultimate Consumers
11
SalesForResaleAbstract
(447) Sales for Resale
103,602,490
63,599,506
1,654,639
923,791
12
SalesOfElectricityAbstract
TOTAL Sales of Electricity
103,602,490
63,599,506
1,654,639
923,791
13
ProvisionForRateRefundsAbstract
(Less) (449.1) Provision for Rate Refunds
31,295,250
1,080,257
14
RevenuesNetOfProvisionForRefundsAbstract
TOTAL Revenues Net of Prov. for Refunds
72,307,240
62,519,249
1,654,639
923,791
15
OtherOperatingRevenuesAbstract
Other Operating Revenues
16
ForfeitedDiscounts
(450) Forfeited Discounts
198,351
201,077
17
MiscellaneousServiceRevenues
(451) Miscellaneous Service Revenues
(a)
1,863,484
1,874,717
18
SalesOfWaterAndWaterPower
(453) Sales of Water and Water Power
19
RentFromElectricProperty
(454) Rent from Electric Property
20,931,813
20,601,626
20
InterdepartmentalRents
(455) Interdepartmental Rents
21
OtherElectricRevenue
(456) Other Electric Revenues
(b)
913,671,775
884,531,881
22
RevenuesFromTransmissionOfElectricityOfOthers
(456.1) Revenues from Transmission of Electricity of Others
313,423,362
293,788,617
23
RegionalTransmissionServiceRevenues
(457.1) Regional Control Service Revenues
24
MiscellaneousRevenue
(457.2) Miscellaneous Revenues
25
OtherMiscellaneousOperatingRevenues
Other Miscellaneous Operating Revenues
26
OtherOperatingRevenues
TOTAL Other Operating Revenues
1,250,088,785
1,200,997,918
27
ElectricOperatingRevenues
TOTAL Electric Operating Revenues
1,322,396,025
1,263,517,167


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MiscellaneousServiceRevenues

Customer service revenue, including connects, reconnects, disconnects, temporary services, and other charges billed to customers. (Applies to current and previous year).

(b) Concept: OtherElectricRevenue

Account 456.0 Other Electric Revenues:

2018

2017

Wires Revenue (Billed & Unbilled)*

903,747,320

875,124,484

Demand-Side Management Program

(1,340,319)

(1,531,501)

Electric Operations - Nonaffiliated

1,328,633

1,347,953

Third Party Plant Operations including related overhead

1,207,339

980,349

Amortization of Deferred Equity Income - Transition

 

 

Funding III

7,258,952

7,140,746

Electric Operations - Affiliated

1,469,850

1,469,850

Total

913,671,775

884,531,881

 

*AEP Texas sells wire services through Retail Electric Providers in Texas and therefore, records both "Billed and Unbilled Revenues" in account 4560 - Other Electric Revenues.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed - All Accounts
42 TOTAL Unbilled Rev. (See Instr. 6) - All Accounts
43 TOTAL - All Accounts


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
(a)
AEP Energy Partners, Inc.
1,654,639
59,923,218
43,679,272
103,602,490
15
Subtotal - RQ
16
Subtotal-Non-RQ
(e)(f)
1,654,639
59,923,218
43,679,272
103,602,490
17 Total
1,654,639
59,923,218
43,679,272
103,602,490


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityReceivingElectricityPurchasedForResale

AEP Energy Partners (AEPEP), an affiliated company, Oklaunion Power Purchase and Sales Agreement.

(b) Concept: AverageMonthlyBillingDemand
Original value: N/A
(c) Concept: AverageMonthlyNonCoincidentPeakDemand
Original value: N/A
(d) Concept: AverageMonthlyCoincidentPeakDemand
Original value: N/A
(e) Concept: MegawattHoursSoldNonRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 1788559
(f) Concept: MegawattHoursSoldNonRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 0

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2,343,027
2,179,461
5
FuelSteamPowerGeneration
(501) Fuel
37,803,384
20,343,982
6
SteamExpensesSteamPowerGeneration
(502) Steam Expenses
1,535,775
1,312,179
7
SteamFromOtherSources
(503) Steam from Other Sources
8
SteamTransferredCredit
(Less) (504) Steam Transferred-Cr.
9
ElectricExpensesSteamPowerGeneration
(505) Electric Expenses
1,162,016
1,028,382
10
MiscellaneousSteamPowerExpenses
(506) Miscellaneous Steam Power Expenses
5,547,411
1,821,163
11
RentsSteamPowerGeneration
(507) Rents
12
Allowances
(509) Allowances
13
SteamPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 4 thru 12)
48,391,613
26,685,167
14
SteamPowerGenerationMaintenanceAbstract
Maintenance
15
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
(510) Maintenance Supervision and Engineering
718,758
679,693
16
MaintenanceOfStructuresSteamPowerGeneration
(511) Maintenance of Structures
935,180
776,061
17
MaintenanceOfBoilerPlantSteamPowerGeneration
(512) Maintenance of Boiler Plant
3,952,645
3,775,128
18
MaintenanceOfElectricPlantSteamPowerGeneration
(513) Maintenance of Electric Plant
640,063
559,905
19
MaintenanceOfMiscellaneousSteamPlant
(514) Maintenance of Miscellaneous Steam Plant
364,169
252,470
20
SteamPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 15 thru 19)
6,610,815
6,043,257
21
PowerProductionExpensesSteamPower
TOTAL Power Production Expenses-Steam Power (Enter Total of Lines 13 & 20)
55,002,428
32,728,424
22
NuclearPowerGenerationAbstract
B. Nuclear Power Generation
23
NuclearPowerGenerationOperationAbstract
Operation
24
OperationSupervisionAndEngineeringNuclearPowerGeneration
(517) Operation Supervision and Engineering
25
NuclearFuelExpense
(518) Fuel
26
CoolantsAndWater
(519) Coolants and Water
27
SteamExpensesNuclearPowerGeneration
(520) Steam Expenses
28
SteamFromOtherSourcesNuclearPowerGeneration
(521) Steam from Other Sources
29
SteamTransferredCreditNuclearPowerGeneration
(Less) (522) Steam Transferred-Cr.
30
ElectricExpensesNuclearPowerGeneration
(523) Electric Expenses
31
MiscellaneousNuclearPowerExpenses
(524) Miscellaneous Nuclear Power Expenses
32
RentsNuclearPowerGeneration
(525) Rents
33
NuclearPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of lines 24 thru 32)
34
NuclearPowerGenerationMaintenanceAbstract
Maintenance
35
MaintenanceSupervisionAndEngineeringNuclearPowerGeneration
(528) Maintenance Supervision and Engineering
36
MaintenanceOfStructuresNuclearPowerGeneration
(529) Maintenance of Structures
37
MaintenanceOfReactorPlantEquipmentNuclearPowerGeneration
(530) Maintenance of Reactor Plant Equipment
38
MaintenanceOfElectricPlantNuclearPowerGeneration
(531) Maintenance of Electric Plant
39
MaintenanceOfMiscellaneousNuclearPlant
(532) Maintenance of Miscellaneous Nuclear Plant
40
NuclearPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 35 thru 39)
41
PowerProductionExpensesNuclearPower
TOTAL Power Production Expenses-Nuclear. Power (Enter Total of lines 33 & 40)
42
HydraulicPowerGenerationAbstract
C. Hydraulic Power Generation
43
HydraulicPowerGenerationOperationAbstract
Operation
44
OperationSupervisionAndEngineeringHydraulicPowerGeneration
(535) Operation Supervision and Engineering
45
WaterForPower
(536) Water for Power
46
HydraulicExpenses
(537) Hydraulic Expenses
47
ElectricExpensesHydraulicPowerGeneration
(538) Electric Expenses
48
MiscellaneousHydraulicPowerGenerationExpenses
(539) Miscellaneous Hydraulic Power Generation Expenses
49
RentsHydraulicPowerGeneration
(540) Rents
50
HydraulicPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 44 thru 49)
51
HydraulicPowerGenerationContinuedAbstract
C. Hydraulic Power Generation (Continued)
52
HydraulicPowerGenerationMaintenanceAbstract
Maintenance
53
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
(541) Mainentance Supervision and Engineering
54
MaintenanceOfStructuresHydraulicPowerGeneration
(542) Maintenance of Structures
55
MaintenanceOfReservoirsDamsAndWaterways
(543) Maintenance of Reservoirs, Dams, and Waterways
56
MaintenanceOfElectricPlantHydraulicPowerGeneration
(544) Maintenance of Electric Plant
57
MaintenanceOfMiscellaneousHydraulicPlant
(545) Maintenance of Miscellaneous Hydraulic Plant
58
HydraulicPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of lines 53 thru 57)
59
PowerProductionExpensesHydraulicPower
TOTAL Power Production Expenses-Hydraulic Power (Total of Lines 50 & 58)
60
OtherPowerGenerationAbstract
D. Other Power Generation
61
OtherPowerGenerationOperationAbstract
Operation
62
OperationSupervisionAndEngineeringOtherPowerGeneration
(546) Operation Supervision and Engineering
63
Fuel
(547) Fuel
7
64
GenerationExpenses
(548) Generation Expenses
64.1
OperationOfEnergyStorageEquipment
(548.1) Operation of Energy Storage Equipment
65
MiscellaneousOtherPowerGenerationExpenses
(549) Miscellaneous Other Power Generation Expenses
66
RentsOtherPowerGeneration
(550) Rents
67
OtherPowerGenerationOperationsExpense
TOTAL Operation (Enter Total of Lines 62 thru 67)
7
68
OtherPowerGenerationMaintenanceAbstract
Maintenance
69
MaintenanceSupervisionAndEngineeringOtherPowerGeneration
(551) Maintenance Supervision and Engineering
70
MaintenanceOfStructures
(552) Maintenance of Structures
71
MaintenanceOfGeneratingAndElectricPlant
(553) Maintenance of Generating and Electric Plant
71.1
MaintenanceOfEnergyStorageEquipmentOtherPowerGeneration
(553.1) Maintenance of Energy Storage Equipment
72
MaintenanceOfMiscellaneousOtherPowerGenerationPlant
(554) Maintenance of Miscellaneous Other Power Generation Plant
73
OtherPowerGenerationMaintenanceExpense
TOTAL Maintenance (Enter Total of Lines 69 thru 72)
74
PowerProductionExpensesOtherPower
TOTAL Power Production Expenses-Other Power (Enter Total of Lines 67 & 73)
7
75
OtherPowerSuplyExpensesAbstract
E. Other Power Supply Expenses
76
PurchasedPower
(555) Purchased Power
76.1
PowerPurchasedForStorageOperations
(555.1) Power Purchased for Storage Operations
77
SystemControlAndLoadDispatchingElectric
(556) System Control and Load Dispatching
191,913
162,262
78
OtherExpensesOtherPowerSupplyExpenses
(557) Other Expenses
614
208
79
OtherPowerSupplyExpense
TOTAL Other Power Supply Exp (Enter Total of Lines 76 thru 78)
192,527
162,470
80
PowerProductionExpenses
TOTAL Power Production Expenses (Total of Lines 21, 41, 59, 74 & 79)
55,194,962
32,890,894
81
TransmissionExpensesAbstract
2. TRANSMISSION EXPENSES
82
TransmissionExpensesOperationAbstract
Operation
83
OperationSupervisionAndEngineeringElectricTransmissionExpenses
(560) Operation Supervision and Engineering
16,511,096
10,395,930
85
LoadDispatchReliability
(561.1) Load Dispatch-Reliability
4,860
86
LoadDispatchMonitorAndOperateTransmissionSystem
(561.2) Load Dispatch-Monitor and Operate Transmission System
2,432,894
1,775,400
87
LoadDispatchTransmissionServiceAndScheduling
(561.3) Load Dispatch-Transmission Service and Scheduling
1,746
12,665
88
SchedulingSystemControlAndDispatchServices
(561.4) Scheduling, System Control and Dispatch Services
47,794
63,672
89
ReliabilityPlanningAndStandardsDevelopment
(561.5) Reliability, Planning and Standards Development
344,550
247,754
90
TransmissionServiceStudies
(561.6) Transmission Service Studies
35
22
91
GenerationInterconnectionStudies
(561.7) Generation Interconnection Studies
92
ReliabilityPlanningAndStandardsDevelopmentServices
(561.8) Reliability, Planning and Standards Development Services
93
StationExpensesTransmissionExpense
(562) Station Expenses
818,962
822,612
93.1
OperationOfEnergyStorageEquipmentTransmissionExpense
(562.1) Operation of Energy Storage Equipment
94
OverheadLineExpense
(563) Overhead Lines Expenses
339,705
380,969
95
UndergroundLineExpensesTransmissionExpense
(564) Underground Lines Expenses
96
TransmissionOfElectricityByOthers
(565) Transmission of Electricity by Others
297,238,078
288,349,435
97
MiscellaneousTransmissionExpenses
(566) Miscellaneous Transmission Expenses
6,618,645
4,862,806
98
RentsTransmissionElectricExpense
(567) Rents
3,385
99
TransmissionOperationExpense
TOTAL Operation (Enter Total of Lines 83 thru 98)
324,353,505
306,894,180
100
TransmissionMaintenanceAbstract
Maintenance
101
MaintenanceSupervisionAndEngineeringElectricTransmissionExpenses
(568) Maintenance Supervision and Engineering
77,816
165,865
102
MaintenanceOfStructuresTransmissionExpense
(569) Maintenance of Structures
50,781
31,307
103
MaintenanceOfComputerHardwareTransmission
(569.1) Maintenance of Computer Hardware
13,292
(a)
7,873
104
MaintenanceOfComputerSoftwareTransmission
(569.2) Maintenance of Computer Software
1,008,897
923,659
105
MaintenanceOfCommunicationEquipmentElectricTransmission
(569.3) Maintenance of Communication Equipment
434,925
300,491
106
MaintenanceOfMiscellaneousRegionalTransmissionPlant
(569.4) Maintenance of Miscellaneous Regional Transmission Plant
107
MaintenanceOfStationEquipmentTransmission
(570) Maintenance of Station Equipment
6,596,559
3,686,772
107.1
MaintenanceOfEnergyStorageEquipmentTransmission
(570.1) Maintenance of Energy Storage Equipment
108
MaintenanceOfOverheadLinesTransmission
(571) Maintenance of Overhead Lines
11,547,919
6,857,619
109
MaintenanceOfUndergroundLinesTransmission
(572) Maintenance of Underground Lines
2,102
1,291
110
MaintenanceOfMiscellaneousTransmissionPlant
(573) Maintenance of Miscellaneous Transmission Plant
24,488
94,094
111
TransmissionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 101 thru 110)
19,707,803
12,068,971
112
TransmissionExpenses
TOTAL Transmission Expenses (Total of Lines 99 and 111)
344,061,308
318,963,151
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
122
RentsRegionalMarketExpenses
(575.8) Rents
123
RegionalMarketOperationExpense
Total Operation (Lines 115 thru 122)
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)
132
DistributionExpensesAbstract
4. DISTRIBUTION EXPENSES
133
DistributionExpensesOperationAbstract
Operation
134
OperationSupervisionAndEngineeringDistributionExpense
(580) Operation Supervision and Engineering
7,732,452
7,258,361
135
LoadDispatching
(581) Load Dispatching
3,452,163
3,221,370
136
StationExpensesDistribution
(582) Station Expenses
1,572,942
1,374,181
137
OverheadLineExpenses
(583) Overhead Line Expenses
6,065,648
4,168,308
138
UndergroundLineExpenses
(584) Underground Line Expenses
1,264,211
1,368,913
138.1
OperationOfEnergyStorageEquipmentDistribution
(584.1) Operation of Energy Storage Equipment
139
StreetLightingAndSignalSystemExpenses
(585) Street Lighting and Signal System Expenses
102,722
107,982
140
MeterExpenses
(586) Meter Expenses
7,384,636
8,777,477
141
CustomerInstallationsExpenses
(587) Customer Installations Expenses
1,216,737
1,204,954
142
MiscellaneousDistributionExpenses
(588) Miscellaneous Expenses
27,943,070
24,825,585
143
RentsDistributionExpense
(589) Rents
1,948,928
1,774,149
144
DistributionOperationExpensesElectric
TOTAL Operation (Enter Total of Lines 134 thru 143)
58,683,509
54,081,280
145
DistributionExpensesMaintenanceAbstract
Maintenance
146
MaintenanceSupervisionAndEngineering
(590) Maintenance Supervision and Engineering
155,020
132,269
147
MaintenanceOfStructuresDistributionExpense
(591) Maintenance of Structures
23,147
21,600
148
MaintenanceOfStationEquipment
(592) Maintenance of Station Equipment
2,665,397
2,834,173
148.1
MaintenanceOfEnergyStorageEquipment
(592.2) Maintenance of Energy Storage Equipment
149
MaintenanceOfOverheadLines
(593) Maintenance of Overhead Lines
37,955,120
36,985,465
150
MaintenanceOfUndergroundLines
(594) Maintenance of Underground Lines
1,987,925
1,145,884
151
MaintenanceOfLineTransformers
(595) Maintenance of Line Transformers
1,152,140
765,787
152
MaintenanceOfStreetLightingAndSignalSystems
(596) Maintenance of Street Lighting and Signal Systems
889,423
624,476
153
MaintenanceOfMeters
(597) Maintenance of Meters
456,416
387,816
154
MaintenanceOfMiscellaneousDistributionPlant
(598) Maintenance of Miscellaneous Distribution Plant
225,093
341,929
155
DistributionMaintenanceExpenseElectric
TOTAL Maintenance (Total of Lines 146 thru 154)
45,509,681
43,239,399
156
DistributionExpenses
TOTAL Distribution Expenses (Total of Lines 144 and 155)
104,193,190
97,320,679
157
CustomerAccountsExpensesAbstract
5. CUSTOMER ACCOUNTS EXPENSES
158
CustomerAccountsExpensesOperationsAbstract
Operation
159
SupervisionCustomerAccountExpenses
(901) Supervision
684,430
629,303
160
MeterReadingExpenses
(902) Meter Reading Expenses
432,431
376,050
161
CustomerRecordsAndCollectionExpenses
(903) Customer Records and Collection Expenses
10,360,283
9,891,753
162
UncollectibleAccounts
(904) Uncollectible Accounts
750,907
157,400
163
MiscellaneousCustomerAccountsExpenses
(905) Miscellaneous Customer Accounts Expenses
120,030
99,174
164
CustomerAccountExpenses
TOTAL Customer Accounts Expenses (Enter Total of Lines 159 thru 163)
12,348,081
11,153,680
165
CustomerServiceAndInformationalExpensesAbstract
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166
CustomerServiceAndInformationalExpensesOperationAbstract
Operation
167
SupervisionCustomerServiceAndInformationExpenses
(907) Supervision
17,473,565
15,806,190
168
CustomerAssistanceExpenses
(908) Customer Assistance Expenses
1,559,077
1,567,026
169
InformationalAndInstructionalAdvertisingExpenses
(909) Informational and Instructional Expenses
286
20
170
MiscellaneousCustomerServiceAndInformationalExpenses
(910) Miscellaneous Customer Service and Informational Expenses
9,638
238,033
171
CustomerServiceAndInformationExpenses
TOTAL Customer Service and Information Expenses (Total Lines 167 thru 170)
19,042,566
17,611,269
172
SalesExpenseAbstract
7. SALES EXPENSES
173
SalesExpenseOperationAbstract
Operation
174
SupervisionSalesExpense
(911) Supervision
14
2,241
175
DemonstratingAndSellingExpenses
(912) Demonstrating and Selling Expenses
318,124
295,574
176
AdvertisingExpenses
(913) Advertising Expenses
177
MiscellaneousSalesExpenses
(916) Miscellaneous Sales Expenses
178
SalesExpenses
TOTAL Sales Expenses (Enter Total of Lines 174 thru 177)
318,138
297,815
179
AdministrativeAndGeneralExpensesAbstract
8. ADMINISTRATIVE AND GENERAL EXPENSES
180
AdministrativeAndGeneralExpensesOperationAbstract
Operation
181
AdministrativeAndGeneralSalaries
(920) Administrative and General Salaries
30,862,490
26,993,029
182
OfficeSuppliesAndExpenses
(921) Office Supplies and Expenses
3,020,246
2,672,895
183
AdministrativeExpensesTransferredCredit
(Less) (922) Administrative Expenses Transferred-Credit
9,515,991
3,849,034
184
OutsideServicesEmployed
(923) Outside Services Employed
8,412,198
5,036,037
185
PropertyInsurance
(924) Property Insurance
2,686,581
2,591,626
186
InjuriesAndDamages
(925) Injuries and Damages
4,720,125
5,073,129
187
EmployeePensionsAndBenefits
(926) Employee Pensions and Benefits
1,600,491
8,682,060
188
FranchiseRequirements
(927) Franchise Requirements
189
RegulatoryCommissionExpenses
(928) Regulatory Commission Expenses
1,672,980
326,093
190
DuplicateChargesCredit
(929) (Less) Duplicate Charges-Cr.
191
GeneralAdvertisingExpenses
(930.1) General Advertising Expenses
480,021
427,004
192
MiscellaneousGeneralExpenses
(930.2) Miscellaneous General Expenses
1,895,241
936,383
193
RentsAdministrativeAndGeneralExpense
(931) Rents
925,647
931,218
194
AdministrativeAndGeneralOperationExpense
TOTAL Operation (Enter Total of Lines 181 thru 193)
43,559,047
49,820,440
195
AdministrativeAndGeneralExpensesMaintenanceAbstract
Maintenance
196
MaintenanceOfGeneralPlant
(935) Maintenance of General Plant
17,601,556
14,553,934
197
AdministrativeAndGeneralExpenses
TOTAL Administrative & General Expenses (Total of Lines 194 and 196)
61,160,603
64,374,374
198
OperationsAndMaintenanceExpensesElectric
TOTAL Electric Operation and Maintenance Expenses (Total of Lines 80, 112, 131, 156, 164, 171, 178, and 197)
596,318,848
542,611,862


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MaintenanceOfComputerHardwareTransmission

 

This footnote applies to both current and prior year.

 

 

Allocated maintenance expenses for joint use computer hardware, computer software and

communication equipment are determined by using various factors, which include number

of remote terminal units, number of radios, number of employees and other factors

assigned to each function.

 

 


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15 TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
American Electric Power
2
(a)
Service Corporation (1,2)
Various
Various
Various
Various
3
Austin Energy (2)
Various
Various
Various
Various
13,082,697
13,082,697
4
Bandera Electric Coop (2)
Various
Various
Various
Various
712,620
712,620
5
Bartlett, City of (2)
Various
Various
Various
Various
13,242
13,242
6
Bastrop, City of (2)
Various
Various
Various
Various
84,330
84,330
7
Bellville, City of (2)
Various
Various
Various
Various
66,352
66,352
8
Bluebonnet Electric Coop (2)
Various
Various
Various
Various
2,237,919
2,237,919
9
Boerne, City of (2)
Various
Various
Various
Various
163,146
163,146
10
Brady, City of (2)
Various
Various
Various
Various
73,042
73,042
11
Brazos Electric Coop (2)
Various
Various
Various
Various
16,300,041
16,300,041
12
Brenham, City of (2)
Various
Various
Various
Various
287,296
287,296
13
Bridgeport, City of (2)
Various
Various
Various
Various
71,417
71,417
14
Brownsville Public Utilities Board (2)
Various
Various
Various
Various
1,337,889
1,337,889
15
Bryan Texas Utilities (2)
Various
Various
Various
Various
1,262,777
1,262,777
16
Burnet, City of (2)
Various
Various
Various
Various
92,076
92,076
17
Calpine Power Service Company (3)
ERCOT
SPP
Various
Various
34,483
34,483
45,802
45,802
18
Canadian Wood Products Energy (3)
ERCOT
SPP
Various
Various
120,304
120,304
94,939
94,939
19
Cargill Power Marketing LLC (2)
Various
Various
Various
Various
20
Centerpoint Energy Houston Electric, LLC (2)
Various
Various
Various
Various
85,355,978
85,355,978
21
Central Texas Electric Coop (2)
Various
Various
Various
Various
653,215
653,215
22
Coleman, City of (2)
Various
Various
Various
Various
50,057
50,057
23
College Station, City of (2)
Various
Various
Various
Various
996,319
996,319
24
Constellation Energy Commodities (2)
ERCOT
Various
Various
Various
25
Cuero, City of (2)
Various
Various
Various
Various
105,935
105,935
26
Denton Municipal Electric (2)
Various
Various
Various
Various
1,145,419
1,145,419
27
Dynasty Power (3)
ERCOT
SPP
Various
Various
25,070
25,070
36,841
36,841
28
EDF TRADING N A, LLC (2)
Various
Various
Various
Various
29
Endure Energy LLC (3)
ERCOT
SPP
Various
Various
135,328
135,328
95,176
95,176
30
Farmersville, City of (2)
Various
Various
Various
Various
35,502
35,502
31
Fayette Electric Cooperative (2)
Various
Various
Various
Various
306,372
306,372
32
Flatonia, City of (2)
Various
Various
Various
Various
27,804
27,804
33
Floresville Electric Power System (2)
Various
Various
Various
Various
390,374
390,374
34
Fredericksburg, City of (2)
Various
Various
Various
Various
167,600
167,600
35
Garland Power and Light (2)
Various
Various
Various
Various
1,019,774
1,019,774
36
Georgetown, City of (2)
Various
Various
Various
Various
734,641
734,641
37
GEUS (2)
Various
Various
Various
Various
293,279
293,279
38
Giddings, City of (2)
Various
Various
Various
Various
64,731
64,731
39
Golden Spread Electric Cooperative, Inc (2)
Various
Various
Various
Various
561,542
561,542
40
Goldsmith, City of (2)
Various
Various
Various
Various
4,314
4,314
41
Goldthwaite, City of (2)
Various
Various
Various
Various
24,663
24,663
42
Gonzales, City of (2)
Various
Various
Various
Various
94,535
94,535
43
Granbury Municipal Utilities (2)
Various
Various
Various
Various
100,901
100,901
44
Greenbelt Electric Coop (2)
Various
Various
Various
Various
45
Guadalupe Valley Electric Coop (2)
Various
Various
Various
Various
1,966,555
1,966,555
46
Hallettsville, City of (2)
Various
Various
Various
Various
46,755
46,755
47
Hamilton County Electric Coop (2)
Various
Various
Various
Various
180,357
180,357
48
Hearne, City of (2)
Various
Various
Various
Various
60,890
60,890
49
Hempstead, City of (2)
Various
Various
Various
Various
60,790
60,790
50
J. Aron & Company LLC (3)
ERCOT
SPP
Various
Various
243,288
243,288
298,514
298,514
51
Kerrville Public Utility Board (2)
Various
Various
Various
Various
560,091
560,091
52
LaGrange Utilities (2)
Various
Various
Various
Various
81,072
81,072
53
Lamar County Electric Cooperative (2)
Various
Various
Various
Various
226,493
226,493
54
Lampasas, City of (2)
Various
Various
Various
Various
117,087
117,087
55
Lexington, City of (2)
Various
Various
Various
Various
14,105
14,105
56
Lighthouse Electric Cooperative Inc (2)
Various
Various
Various
Various
57
Llano, City of (2)
Various
Various
Various
Various
52,621
52,621
58
Lockhart, City of (2)
Various
Various
Various
Various
132,327
132,327
59
Luling, City of (2)
Various
Various
Various
Various
63,228
63,228
60
Lyntegar Electric Coop (2)
Various
Various
Various
Various
152,681
152,681
61
Macquarie Energy LLC (3)
ERCOT
SPP
Various
Various
27,918
27,918
23,031
23,031
62
MAG Energy Solutions. Inc. (3)
ERCOT
SPP
Various
Various
2,944
2,944
1,910
1,910
63
Mason, City of (2)
Various
Various
Various
Various
27,234
27,234
64
Mercuria Energy America, Inc. (2)
Various
Various
Various
Various
65
Moulton, City of (2)
Various
Various
Various
Various
11,947
11,947
66
New Braunfels Utilities (2)
Various
Various
Various
Various
1,429,044
1,429,044
67
Oncor Electric Delivery (2)
Various
Various
Various
Various
122,841,531
122,841,531
68
Pedernales Electric Cooperative, Inc (2)
Various
Various
Various
Various
6,929,648
6,929,648
69
Rainbow Energy Marketing (3)
ERCOT
SPP
Various
Various
444,025
444,025
440,863
440,863
70
Rayburn Country Electric Cooperative, Inc (2)
Various
Various
Various
Various
3,614,878
3,614,878
71
Rio Grande Electric Coop (2)
Various
Various
Various
Various
271,528
271,528
72
Robstown Utility System, City of (2)
Various
Various
Various
Various
118,737
118,737
73
San Antonio City Public Service (2)
Various
Various
Various
Various
23,825,136
23,825,136
74
San Bernard Electric Coop (2)
Various
Various
Various
Various
695,697
695,697
75
San Marcos, City of (2)
Various
Various
Various
Various
636,563
636,563
76
San Saba, City of (2)
Various
Various
Various
Various
46,561
46,561
77
Sanger, City of (2)
Various
Various
Various
Various
81,961
81,961
78
Schulenberg, City of (2)
Various
Various
Various
Various
68,049
68,049
79
Seguin, City of (2)
Various
Various
Various
Various
324,032
324,032
80
Sempra Energy Solutions, LLC (3)
ERCOT
SPP
Various
Various
27,041
27,041
16,059
16,059
81
Seymour, City of (2)
Various
Various
Various
Various
40,404
40,404
82
Sharyland Utilities, LP (2)
Various
Various
Various
Various
83
Shell Energy North America
ERCOT
SPP
Various
Various
2,984
2,984
4,685
4,685
84
Shiner, City of (2)
Various
Various
Various
Various
47,792
47,792
85
Smithville, City of (2)
Various
Various
Various
Various
50,078
50,078
86
South Texas Electric Cooperative, Inc (2)
Various
Various
Various
Various
6,519,775
6,519,775
87
Southwest Rural Electric Association INC (2)
Various
Various
Various
Various
756
756
88
Southwest Texas Electric Cooperative, Inc (2)
Various
Various
Various
Various
202,601
202,601
89
Taylor Electric Cooperative, Inc (2)
Various
Various
Various
Various
311,927
311,927
90
Tenaska Power Service Company (3)
ERCOT
SPP
Various
Various
111,303
111,303
99,331
99,331
91
Texas Municipal Power Agency (2)
Various
Various
Various
Various
2,334,291
2,334,291
92
Texas-New Mexico Power Company (2)
Various
Various
Various
Various
8,427,385
8,427,385
93
Tex-La Electric Coop (2)
Various
Various
Various
Various
570,128
570,128
94
The Energy Authority (3)
ERCOT
SPP
Various
Various
13,551
13,551
8,319
8,319
95
Twin Eagle Resource Management LLC (3)
ERCOT
SPP
Various
Various
257,669
257,669
180,402
180,402
96
Vitol, Inc (3)
ERCOT
SPP
Various
Various
246,091
246,091
323,098
323,098
97
Waelder, City of (2)
Various
Various
Various
Various
23,402
23,402
98
Weatherford, City of (2)
Various
Various
Various
Various
458,107
458,107
99
Weimer, City of (2)
Various
Various
Various
Various
39,504
39,504
100
Westar Energy Inc. (3)
ERCOT
SPP
Various
Various
84,751
84,751
71,995
71,995
101
Western Farmers Electric Cooperative (2)
Various
Various
Various
Various
3,970
3,970
102
Yoakum, City of (2)
Various
Various
Various
Various
96,880
96,880
35 TOTAL
1,776,750
1,776,750
313,423,362
313,423,362


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PaymentByCompanyOrPublicAuthority

(1) Respondent is an affiliated company of American Electric Power Service Corporation and American Electric Power Energy Partners, Inc.

 

(2) Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

 

(3) High Voltage Direct Current Tie


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
40
TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
American Electric Power
2
Service
3
(a)
Corporation (1, 2, 3)
505,815
505,815
4
Austin Energy (2)
7,083,644
7,083,644
5
Bandera Electric
6
Cooperative (2)
279,295
279,295
7
Brazos Electric
8
Cooperative (2)
11,232,414
11,232,414
9
Brownsville Public
10
Utilities Board (2)
585,480
585,480
11
Bryan Texas
12
Utilities (2)
2,629,241
2,629,241
13
Centerpoint Energy
14
Houston Electric (2)
33,967,601
33,967,601
15
Cherokee County
16
Electric Cooperative(2)
30,240
30,240
17
College Station,
18
City of (2)
333,521
333,521
19
Cross Texas
20
Transmission (2, 4)
6,238,715
6,238,715
21
Deep East Texas
22
Cooperative (2)
10,321
10,321
23
Denton Municipal
24
Electric (2)
3,342,961
3,342,961
25
East Texas Electric
26
Cooperative (2)
9,693
9,693
27
(b)
Electric Transmission
28
Tx, LLC (2)
27,423,937
27,423,937
29
Fannin Electric
30
Cooperative (2)
14,795
14,795
31
Farmers Electric
32
Cooperative (2)
64,296
64,296
33
Floresville Electric
34
Power System (2)
34,468
34,468
35
Garland Power
36
and Light (2)
3,173,955
3,173,955
37
GEUS (2)
217,473
217,473
38
Golden Spread Electric
39
Cooperative (2)
83,902
83,902
40
Grayson-Collin Electric
126,535
126,535
41
Cooperative (2)
42
Houston County Electric
43
Cooperative (2)
22,956
22,956
44
Lamar County Electric
45
Cooperative (2)
9,921
9,921
46
Lone Star Transmission,
47
LLC (2, 4)
8,305,116
8,305,116
48
Lower Colorado River
49
Authority (LCRA) (2)
38,042,651
38,042,651
50
Lyntegar Electric
51
Cooperative (2)
49,669
49,669
52
Oncor
53
Electric Delivery (2)
78,550,050
78,550,050
54
Rayburn
55
Country Electric
56
Cooperative (2)
360,143
360,143
57
Rio Grande Electric
58
Cooperative (2)
26,739
26,739
59
San Antonio City
60
Public Service (2)
15,675,726
15,675,726
61
San Bernard Electric
62
Cooperative (2)
229,701
229,701
63
San Miguel Electric
64
Cooperative (2)
236,667
236,667
65
Sharyland
66
Utilities, LP (2, 4)
22,885,490
22,885,490
67
South Texas Electric
68
Cooperative (2)
7,213,708
7,213,708
69
Southwest Texas
70
Electric
71
Cooperative (2)
2,424
2,424
72
Taylor Electric
73
Cooperative (2)
63,739
63,739
74
Texas Municipal
75
Power Agency (2)
4,003,399
4,003,399
76
Texas-New Mexico
77
Power Company (2)
6,133,265
6,133,265
78
Transmission Cost
79
Recovery Factor (5)
7,735,503
7,735,503
80
Trinity Valley Electric
81
Cooperative (2)
165,978
165,978
82
Wind Energy
83
Transmission Texas(2,4)
10,121,322
10,121,322
84
Wood County Electric
85
Cooperative (2)
15,609
15,609
TOTAL
297,238,078
297,238,078


FOOTNOTE DATA

(a) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

(1)

Respondent is an affiliated company of American Electric Power Service Corporation

 

 

(2)

Transmission Cost of Service pursuant to Texas Substantive Rule 23.67

 

 

(3)

High Voltage Direct Current (HVDC) East Tie facilities charge

 

 

(4)

Transmission service surcharge

 

 

(5)

Transmission Cost Recovery Factor Deferral

 

(b) Concept: NameOfCompanyOrPublicAuthorityTransmissionOfElectricityByOthers

Electric Transmission Texas, LLC (ETT) is a joint venture of which American Electric Power is a 50% member.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
527,258
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
86,997
5
OtherMiscellaneousGeneralExpenses
Oth Expn greater than or equal to 5,000 show purpose, recipient, amount. Group if less than $5,000
40,060
6
Associated Business Development
947,409
7
Misc. General Service & Affiliated Companies Billing
255,891
8
Chamber of Commerce
37,626
46
MiscellaneousGeneralExpenses
TOTAL
1,895,241


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
24,054,567
24,054,567
2
Steam Production Plant
22,375,773
2,795,553
25,171,326
3
Nuclear Production Plant
4
Hydraulic Production Plant-Conventional
5
Hydraulic Production Plant-Pumped Storage
6
Other Production Plant
7
Transmission Plant
63,266,753
63,266,753
8
Distribution Plant
133,593,752
133,593,752
9
Regional Transmission and Market Operation
10
General Plant
16,036,234
82,605
16,118,839
11
Common Plant-Electric
12
TOTAL
235,272,512
2,878,158
24,054,567
262,205,237
B. Basis for Amortization Charges
Section A Line 1 Column D represents amortization of capitalized software development costs over a 5 year life and costs associated with the Oracle strategic partnership which are over a 10 year life.
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
0 years
0 years
14
327,050
0 years
0 years
15
327,050
0 years
0 years
16
0 years
0 years
17
0 years
0 years
18
56,951
(b)
75 years
1.02
R5
0 years
19
27,345
(c)
55 years
1
1.33
L1
0 years
20
1,191,126
(d)
62 years
1
1.38
L0.5
0 years
21
2,656
(e)
62 years
1
1.38
L0.5
0 years
22
46,652
(f)
81 years
2
0.8
S3
0 years
23
542,814
(g)
70 years
68
2.18
R1
0 years
24
478,720
(h)
75 years
29
1.52
R3
0 years
25
6,641
(i)
75 years
29
1.52
R3
0 years
26
2,243
(j)
65 years
5
0.59
R2
0 years
27
24,960
(k)
50 years
1.66
R3
0 years
28
31
(l)
50 years
1.66
R3
0 years
29
54
(m)
65 years
1.15
R4
0 years
30
2,380,193
0 years
0 years
31
0 years
0 years
32
25,668
(n)
75 years
0.92
R3
0 years
33
15,595
(o)
50 years
1.52
L4
0 years
34
532,061
(p)
54 years
25
1.86
R0.5
0 years
35
1,674
(q)
54 years
25
1.86
R0.5
0 years
36
238
0 years
0 years
37
3,771
(r)
65 years
10
1.79
R3
0 years
38
335,897
(s)
45 years
80
4.62
R5
0 years
39
157,208
(t)
50 years
45
3.32
S6
0 years
40
15,256
(u)
50 years
45
3.32
S6
0 years
41
2,183
(v)
65 years
0.83
R2
0 years
42
58
(w)
50 years
1.66
R3
0 years
43
1,089,609
0 years
0 years
44
3,469,802
0 years
0 years
45
0 years
0 years
46
0 years
0 years
47
1,313
(x)
60 years
1.44
R5
0 years
48
13,992
(y)
64 years
21
0.88
R2.5
0 years
49
395,862
(z)
61 years
28
1.07
L0.5
0 years
50
517
(aa)
61 years
28
1.07
L0.5
0 years
51
649,489
(ab)
39 years
48
3.67
S0.5
0 years
52
599,062
(ac)
54 years
88
3.37
R0.5
0 years
53
57,316
(ad)
60 years
56
2.51
R3
0 years
54
286,005
(ae)
50 years
35
2.6
R1
0 years
55
541,327
(af)
40 years
13
2.55
S0
0 years
56
217,463
(ag)
35 years
41
3.83
SC
0 years
57
31,792
(ah)
22 years
15
5.56
R0.5
0 years
58
149,552
0 years
14.29
0 years
59
55,063
(ai)
35 years
12
2.19
L0
0 years
60
85,326
(aj)
35 years
30
3.22
SC
0 years
61
3,084,079
0 years
0 years
62
0 years
0 years
63
2,163
(ak)
55 years
1.37
R2.5
0 years
64
5,421
(al)
52 years
15
2.24
R3
0 years
65
146,702
(am)
37 years
29
3.45
R0.5
0 years
66
457
(an)
37 years
29
3.45
R0.5
0 years
67
198,071
(ao)
35 years
15
3.6
L5
0 years
68
145,570
(ap)
50 years
40
2.72
R0.5
0 years
69
23,197
(aq)
70 years
40
1.79
R1.5
0 years
70
60,016
(ar)
36 years
20
3.03
R1.5
0 years
71
156,208
(as)
39 years
5
2.7
L2
0 years
72
86,456
(at)
30 years
50
6.41
S6
0 years
73
11,491
(au)
40 years
40
3.49
R0.5
0 years
74
38,792
0 years
14.29
0 years
75
15,280
(av)
28 years
56
5.77
R0.5
0 years
76
87
(aw)
50 years
2.89
R3
0 years
77
21,868
(ax)
30 years
10
4.56
S6
0 years
78
911,779
0 years
0 years
79
3,995,858
0 years
0 years
80
0 years
0 years
81
0 years
0 years
82
168,036
(ay)
40 years
19
1.1
R0.5
0 years
83
3,564
(az)
15 years
2
2.77
SQ
0 years
84
186
0 years
5
0 years
85
1,140
(ba)
22 years
8.52
SQ
0 years
86
31,609
(bb)
35 years
3.31
SQ
0 years
87
441
(bc)
33 years
0.58
SQ
0 years
88
192
(bd)
15 years
3
0.94
SQ
0 years
89
64,543
(be)
20 years
6.49
SQ
0 years
90
22,943
0 years
14.29
0 years
91
3,110
(bf)
20 years
2
8.62
SQ
0 years
92
295,764
0 years
0 years
93
0 years
0 years
94
18
(bg)
50 years
1.83
R3
0 years
95
49,829
(bh)
36 years
14
4.69
S3
0 years
96
3
0 years
0 years
97
2,821
(bi)
25 years
1
5.21
SQ
0 years
98
185
0 years
0 years
99
3
(bj)
15 years
19.82
SQ
0 years
100
57
(bk)
15 years
1
6.39
SQ
0 years
101
18
0 years
0 years
102
22
(bl)
20 years
1
5
SQ
0 years
103
1
0 years
0 years
104
146
(bm)
20 years
3
5.66
SQ
0 years
105
29
0 years
0 years
106
15,972
(bn)
25 years
3.54
SQ
0 years
107
51
0 years
0 years
108
1,926
0 years
0 years
109
33
0 years
0 years
110
21,328
(bo)
15 years
1
6.58
SQ
0 years
111
238
0 years
0 years
112
11
(bp)
10 years
9.91
SQ
0 years
113
73
(bq)
22 years
2
3.97
SQ
0 years
114
13,237
0 years
14.29
0 years
115
1,997
(br)
28 years
3.52
SQ
0 years
116
52
0 years
0 years
117
108,050
0 years
0 years
118
403,814
0 years
0 years
119
(a)
8,196,524
0 years
0 years


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: DepreciablePlantBase

The depreciable plant base is the November 30, 2018 total company depreciable plant.

(b) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(c) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 55
(d) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 62
(e) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 62
(f) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 81
(g) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 70
(h) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(i) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(j) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(k) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(l) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(m) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(n) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 75
(o) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(p) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 54
(q) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 54
(r) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(s) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 45
(t) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(u) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(v) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 65
(w) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(x) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(y) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 64
(z) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 61
(aa) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 61
(ab) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 39
(ac) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 54
(ad) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 60
(ae) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(af) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(ag) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(ah) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(ai) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(aj) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(ak) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 55
(al) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 52
(am) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 37
(an) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 37
(ao) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(ap) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(aq) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 70
(ar) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 36
(as) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 39
(at) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 30
(au) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(av) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 28
(aw) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(ax) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 30
(ay) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 40
(az) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(ba) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(bb) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 35
(bc) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 33
(bd) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(be) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bf) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bg) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 50
(bh) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 36
(bi) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(bj) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(bk) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(bl) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bm) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 20
(bn) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 25
(bo) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 15
(bp) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 10
(bq) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 22
(br) Concept: UtilityPlantEstimatedAverageServiceLife
Original value: 28

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
Various Rate Case Expenses pending
2
future PUCT (Public Utility Commission of
3
Texas) approval for collection from
4
customers
149,525
11,123
160,648
6
Expenses incurred relating to 2018 Texas Rate
7
Case
538,901
538,901
Electric
538,901
9
Expenses incurred related to Distribution
10
Cost Recovery Factor Filings -
11
PUCT Docket No.s. 45787, 45788, 47015
12
and 48222
176,161
176,161
Electric
176,161
14
Expenses incurred in Interim Transmission Cost
15
Cases and other Regulatory/Legislative
16
actions relating to Transmission -
17
PUCT Docket Nos 48507 and 48931
124,568
124,568
Electric
124,568
19
Expenses incurred related to managing
20
Formula Rates for AEP's West Operating
21
Companies and Transco's
33,016
33,016
Electric
33,016
23
Expenses incurred relating to Determination
24
of System Restoration Costs - Hurricane
25
Harvey - PUCT Docket No. 48577
706,392
706,392
Electric
706,392
27
Expenses incurred in Energy Efficiency Cost
28
Recovery Factor filings
29,411
29,411
Electric
29,411
30
Minor Items (less than $25,000)
64,531
64,531
Electric
64,531
46
TOTAL
1,672,980
1,672,980
149,525
1,672,980
11,123
160,648


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
A. (2) Transmission
Transmission RD&D Program Mgmt
24,686
24,686
2
A. (3) Distribution
2 Items < $50,000
12,386
12,386
3
Distribution Program Management
4
A. (6) Other
3 Items < $50,000
10,840
10,840
5
11,208
11,208
6
A. (6)(f) Metering
Advanced Metering Equipment
6,810
6,810
7
A. (6)(g) Research General
DTC Walnut Test Facility
5,388
5,388
8
5,667
5,667
9
A. (7) Total Cost Incurred Intermally
76,985
76,985
10
B. Electric R&D External
6 Items < $50,000
18,027
18,027
11
58,461
58,461
12
B. (1) Electric Power Research Institute
EPRI Research Portfolio
383,671
383,671
13
79,347
79,347
14
Information Technology EPRI Annual Research Portfolio
13,018
13,018
15
65,584
65,584
16
9 Items < $50,000
14,259
14,259
17
6,826
6,826
18
B. (4) Research Support to Others
2 Items < $50,000
7,006
7,006
19
B. (5) Total Cost Incurred Externally
646,199
646,199
20
Total
76,985
646,199
723,184


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
5,953,806
4
SalariesAndWagesElectricOperationTransmission
Transmission
4,147,670
5
SalariesAndWagesElectricOperationRegionalMarket
Regional Market
6
SalariesAndWagesElectricOperationDistribution
Distribution
22,223,509
7
SalariesAndWagesElectricOperationCustomerAccounts
Customer Accounts
4,782,023
8
SalariesAndWagesElectricOperationCustomerServiceAndInformational
Customer Service and Informational
2,606,049
9
SalariesAndWagesElectricOperationSales
Sales
10
SalariesAndWagesElectricOperationAdministrativeAndGeneral
Administrative and General
1,462,609
11
SalariesAndWagesElectricOperation
TOTAL Operation (Enter Total of lines 3 thru 10)
41,175,666
12
SalariesAndWagesElectricMaintenanceAbstract
Maintenance
13
SalariesAndWagesElectricMaintenanceProduction
Production
2,228,140
14
SalariesAndWagesElectricMaintenanceTransmission
Transmission
3,182,857
15
SalariesAndWagesElectricMaintenanceRegionalMarket
Regional Market
16
SalariesAndWagesElectricMaintenanceDistribution
Distribution
19,538,226
17
SalariesAndWagesElectricMaintenanceAdministrativeAndGeneral
Administrative and General
3,999,485
18
SalariesAndWagesElectricMaintenance
TOTAL Maintenance (Total of lines 13 thru 17)
28,948,708
19
SalariesAndWagesElectricOperationAndMaintenanceAbstract
Total Operation and Maintenance
20
SalariesAndWagesElectricProduction
Production (Enter Total of lines 3 and 13)
8,181,946
21
SalariesAndWagesElectricTransmission
Transmission (Enter Total of lines 4 and 14)
7,330,527
22
SalariesAndWagesElectricRegionalMarket
Regional Market (Enter Total of Lines 5 and 15)
23
SalariesAndWagesElectricDistribution
Distribution (Enter Total of lines 6 and 16)
41,761,735
24
SalariesAndWagesElectricCustomerAccounts
Customer Accounts (Transcribe from line 7)
4,782,023
25
SalariesAndWagesElectricCustomerServiceAndInformational
Customer Service and Informational (Transcribe from line 8)
2,606,049
26
SalariesAndWagesElectricSales
Sales (Transcribe from line 9)
27
SalariesAndWagesElectricAdministrativeAndGeneral
Administrative and General (Enter Total of lines 10 and 17)
5,462,094
28
SalariesAndWagesElectricOperationAndMaintenance
TOTAL Oper. and Maint. (Total of lines 20 thru 27)
70,124,374
3,854,051
73,978,425
29
SalariesAndWagesGasAbstract
Gas
30
SalariesAndWagesGasOperationAbstract
Operation
31
SalariesAndWagesGasOperationProductionManufacturedGas
Production - Manufactured Gas
32
SalariesAndWagesGasOperationProductionNaturalGas
Production-Nat. Gas (Including Expl. And Dev.)
33
SalariesAndWagesGasOperationOtherGasSupply
Other Gas Supply
34
SalariesAndWagesGasOperationStorageLiquifiedNaturalGasTerminalingAndProcessing
Storage, LNG Terminaling and Processing
35
SalariesAndWagesGasOperationTransmission
Transmission
36
SalariesAndWagesGasOperationDistribution
Distribution
37
SalariesAndWagesGasCustomerAccounts
Customer Accounts
59
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational
39
SalariesAndWagesGasSales
Sales
40
SalariesAndWagesGasOperationAdministrativeAndGeneral
Administrative and General
41
SalariesAndWagesGasOperation
TOTAL Operation (Enter Total of lines 31 thru 40)
42
SalariesAndWagesGasMaintenanceAbstract
Maintenance
43
SalariesAndWagesGasMaintenanceProductionManufacturedGas
Production - Manufactured Gas
44
SalariesAndWagesGasMaintenanceProductionNaturalGas
Production-Natural Gas (Including Exploration and Development)
45
SalariesAndWagesGasMaintenanceOtherGasSupply
Other Gas Supply
46
SalariesAndWagesGasMaintenanceStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing
47
SalariesAndWagesGasMaintenanceTransmission
Transmission
48
SalariesAndWagesGasMaintenanceDistribution
Distribution
49
SalariesAndWagesGasMaintenanceAdministrativeAndGeneral
Administrative and General
50
SalariesAndWagesGasMaintenance
TOTAL Maint. (Enter Total of lines 43 thru 49)
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,
54
SalariesAndWagesGasOtherGasSupply
Other Gas Supply (Enter Total of lines 33 and 45)
55
SalariesAndWagesGasStorageLngTerminalingAndProcessing
Storage, LNG Terminaling and Processing (Total of lines 31 thru
56
SalariesAndWagesGasTransmission
Transmission (Lines 35 and 47)
57
SalariesAndWagesGasDistribution
Distribution (Lines 36 and 48)
37
SalariesAndWagesGasCustomerAccounts
Customer Accounts (Line 37)
59
SalariesAndWagesGasCustomerServiceAndInformational
Customer Service and Informational (Line 38)
60
SalariesAndWagesGasSales
Sales (Line 39)
61
SalariesAndWagesGasAdministrativeAndGeneral
Administrative and General (Lines 40 and 49)
62
SalariesAndWagesGasOperationAndMaintenance
TOTAL Operation and Maint. (Total of lines 52 thru 61)
63
SalariesAndWagesOtherUtilityDepartmentsAbstract
Other Utility Departments
64
SalariesAndWagesOtherUtilityDepartmentsOperationAndMaintenance
Operation and Maintenance
65
SalariesAndWagesOperationsAndMaintenance
TOTAL All Utility Dept. (Total of lines 28, 62, and 64)
70,124,374
3,854,051
73,978,425
66
SalariesAndWagesUtilityPlantAbstract
Utility Plant
67
SalariesAndWagesUtilityPlantConstructionAbstract
Construction (By Utility Departments)
68
SalariesAndWagesUtilityPlantConstructionElectricPlant
Electric Plant
68,129,501
3,744,413
71,873,914
69
SalariesAndWagesUtilityPlantConstructionGasPlant
Gas Plant
70
SalariesAndWagesUtilityPlantConstructionOther
Other (provide details in footnote):
71
SalariesAndWagesUtilityPlantConstruction
TOTAL Construction (Total of lines 68 thru 70)
68,129,501
3,744,413
71,873,914
72
SalariesAndWagesPlantRemovalAbstract
Plant Removal (By Utility Departments)
73
SalariesAndWagesPlantRemovalElectricPlant
Electric Plant
12,997,841
714,364
13,712,205
74
SalariesAndWagesPlantRemovalGasPlant
Gas Plant
75
SalariesAndWagesPlantRemovalOther
Other (provide details in footnote):
76
SalariesAndWagesPlantRemoval
TOTAL Plant Removal (Total of lines 73 thru 75)
12,997,841
714,364
13,712,205
77
SalariesAndWagesOtherAccountsAbstract
Other Accounts (Specify, provide details in footnote):
78
SalariesAndWagesOtherAccountsDescription
152 - Fuel Stock Undistributed
197,770
197,770
79
SalariesAndWagesOtherAccountsDescription
122 - Depr and Amortization
3,684
3,684
80
SalariesAndWagesOtherAccountsDescription
188 - Research & Development
3,103
3,103
81
SalariesAndWagesOtherAccountsDescription
186 - Misc Deferred Debits
3,503,287
3,503,287
82
SalariesAndWagesOtherAccountsDescription
163 - Stores Expense Undistributed
5,411,313
5,411,313
83
SalariesAndWagesOtherAccountsDescription
426 - Political Activities
177,615
177,615
84
SalariesAndWagesOtherAccountsDescription
183 - Prelim Survey
7,044
7,044
85
SalariesAndWagesOtherAccountsDescription
184 - Clearing Accounts
2,894,471
2,894,471
86
SalariesAndWagesOtherAccountsDescription
185 - ODD Temporary Facilities
386,557
386,557
87
SalariesAndWagesOtherAccountsDescription
88
SalariesAndWagesOtherAccountsDescription
89
SalariesAndWagesOtherAccountsDescription
90
SalariesAndWagesOtherAccountsDescription
91
SalariesAndWagesOtherAccountsDescription
92
SalariesAndWagesOtherAccountsDescription
93
SalariesAndWagesOtherAccountsDescription
94
SalariesAndWagesOtherAccountsDescription
95
SalariesAndWagesOtherAccounts
TOTAL Other Accounts
12,578,638
8,312,828
4,265,810
96
SalariesAndWagesGeneralExpense
TOTAL SALARIES AND WAGES
163,830,354
163,830,354


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
2.1 Net Purchases (Account 555.1)
3 Net Sales (Account 447)
4 Transmission Rights
5 Ancillary Services
6 Other Items (list separately)
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
Reactive Supply and Voltage
3
Regulation and Frequency Response
4
Energy Imbalance
5
Operating Reserve - Spinning
6
Operating Reserve - Supplement
7
Other
8
Total (Lines 1 thru 7)


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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: 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 Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MonthlyPeakLoadExcludingIsoAndRto

 

AEP Texas' transmission service is administered through a Regional Transmission

Organization (RTO) and requested information is not available on an individual

company basis.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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)
3
Steam
(a)(b)
1,786,978
23
Requirements Sales for Resale (See instruction 4, page 311.)
4
Nuclear
24
Non-Requirements Sales for Resale (See instruction 4, page 311.)
(c)(d)
1,654,639
5
Hydro-Conventional
25
Energy Furnished Without Charge
6
Hydro-Pumped Storage
26
Energy Used by the Company (Electric Dept Only, Excluding Station Use)
7
Other
(e)
1,581
27
Total Energy Losses
8
Less Energy for Pumping
27.1
Total Energy Stored
9
Net Generation (Enter Total of lines 3 through 8)
(f)
1,788,559
28
TOTAL (Enter Total of Lines 22 Through 27.1) MUST EQUAL LINE 20 UNDER SOURCES
1,788,559
10
Purchases (other than for Energy Storage)
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
(g)
1,776,750
17
Delivered
(h)
1,776,750
18
Net Transmission for Other (Line 16 minus line 17)
19
Transmission By Others Losses
20
TOTAL (Enter Total of Lines 9, 10, 10.1, 14, 18 and 19)
(i)
1,788,559


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: SteamGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 3, Column: b, Value: 0
(b) Concept: SteamGeneration

 

AEP Texas' remaining generating capacity output that is not deactivated has

been transferred to an affiliated company at AEP Texas' cost pursuant to

a 20-year agreement.

 

(c) Concept: MegawattHoursSoldNonRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 1788559
(d) Concept: MegawattHoursSoldNonRequirementsSales
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 24, Column: b, Value: 0
(e) Concept: OtherEnergyGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 7, Column: b, Value: 0
(f) Concept: NetEnergyGeneration
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 9, Column: b, Value: 0
(g) Concept: ElectricPowerWheelingEnergyReceived
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 16, Column: b, Value: 0
(h) Concept: ElectricPowerWheelingEnergyDelivered
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 17, Column: b, Value: 0
(i) Concept: SourcesOfEnergy
Duplicate fact discrepancy. Schedule: 401a - Schedule - Electric Energy Account, Row: 20, Column: b, Value: 0

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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: 0
29
January
178,476
180,725
30
February
151,178
153,083
31
March
141,863
143,650
32
April
86,248
87,335
33
May
156
158
34
June
161,988
164,029
35
July
194,133
196,579
36
August
194,153
196,599
37
September
186,126
188,471
38
October
202,269
204,818
39
November
79,186
80,184
40
December
212,783
215,464
41
Total


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: MonthlyPeakLoad

 

Monthly peak information is no longer available from the Electric Reliability Council of

Texas (ERCOT).

(b) Concept: HourOfMonthlyPeak
Original value: na
(c) Concept: HourOfMonthlyPeak
Original value: na
(d) Concept: HourOfMonthlyPeak
Original value: na
(e) Concept: HourOfMonthlyPeak
Original value: na
(f) Concept: HourOfMonthlyPeak
Original value: na
(g) Concept: HourOfMonthlyPeak
Original value: na
(h) Concept: HourOfMonthlyPeak
Original value: na
(i) Concept: HourOfMonthlyPeak
Original value: na
(j) Concept: HourOfMonthlyPeak
Original value: na
(k) Concept: HourOfMonthlyPeak
Original value: na
(l) Concept: HourOfMonthlyPeak
Original value: na
(m) Concept: HourOfMonthlyPeak
Original value: na

Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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:
(a)
Oklaunion
1
PlantKind
Kind of Plant (Internal Comb, Gas Turb, Nuclear)
Steam
2
PlantConstructionType
Type of Constr (Conventional, Outdoor, Boiler, etc)
Outdoor Boiler
3
YearPlantOriginallyConstructed
Year Originally Constructed
1986
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
1986
5
InstalledCapacityOfPlant
Total Installed Cap (Max Gen Name Plate Ratings-MW)
393.77
6
NetPeakDemandOnPlant
Net Peak Demand on Plant - MW (60 minutes)
360
7
PlantHoursConnectedToLoad
Plant Hours Connected to Load
7,396
8
NetContinuousPlantCapability
Net Continuous Plant Capability (Megawatts)
9
NetContinuousPlantCapabilityNotLimitedByCondenserWater
When Not Limited by Condenser Water
10
NetContinuousPlantCapabilityLimitedByCondenserWater
When Limited by Condenser Water
366
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - KWh
1,788,559,000
13
CostOfLandAndLandRightsSteamProduction
Cost of Plant: Land and Land Rights
6,241,381
14
CostOfStructuresAndImprovementsSteamProduction
Structures and Improvements
50,120,891
15
CostOfEquipmentSteamProduction
Equipment Costs
275,297,299
16
AssetRetirementCostsSteamProduction
Asset Retirement Costs
20,417,918
17
CostOfPlant
Total cost (total 13 thru 20)
352,077,489
18
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 17/5) Including
894.1196
19
OperationSupervisionAndEngineeringExpense
Production Expenses: Oper, Supv, & Engr
2,368,252
20
FuelSteamPowerGeneration
Fuel
37,803,384
21
CoolantsAndWater
Coolants and Water (Nuclear Plants Only)
22
SteamExpensesSteamPowerGeneration
Steam Expenses
1,535,775
23
SteamFromOtherSources
Steam From Other Sources
24
SteamTransferredCredit
Steam Transferred (Cr)
25
ElectricExpensesSteamPowerGeneration
Electric Expenses
1,162,016
26
MiscellaneousSteamPowerExpenses
Misc Steam (or Nuclear) Power Expenses
5,522,205
27
RentsSteamPowerGeneration
Rents
28
Allowances
Allowances
29
MaintenanceSupervisionAndEngineeringSteamPowerGeneration
Maintenance Supervision and Engineering
720,663
30
MaintenanceOfStructuresSteamPowerGeneration
Maintenance of Structures
935,181
31
MaintenanceOfBoilerPlantSteamPowerGeneration
Maintenance of Boiler (or reactor) Plant
3,952,644
32
MaintenanceOfElectricPlantSteamPowerGeneration
Maintenance of Electric Plant
640,078
33
MaintenanceOfMiscellaneousSteamPlant
Maintenance of Misc Steam (or Nuclear) Plant
364,160
34
PowerProductionExpensesSteamPower
Total Production Expenses
55,004,358
35
ExpensesPerNetKilowattHour
Expenses per Net KWh
0.0308
35
FuelKindAxis
Plant Name
Oklaunion
Oklaunion
Oklaunion
36
FuelKind
Fuel Kind
Coal
Composite
Oil
37
FuelUnit
Fuel Unit
TONS
BBLS
38
QuantityOfFuelBurned
Quantity (Units) of Fuel Burned
127,328
312
39
FuelBurnedAverageHeatContent
Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
8,428
136,520
40
AverageCostOfFuelPerUnitAsDelivered
Avg Cost of Fuel/unit, as Delvd f.o.b. during year
37.233
95.209
41
AverageCostOfFuelPerUnitBurned
Average Cost of Fuel per Unit Burned
34.226
91.914
42
AverageCostOfFuelBurnedPerMillionBritishThermalUnit
Average Cost of Fuel Burned per Million BTU
2.03
38.49
43
AverageCostOfFuelBurnedPerKilowattHourNetGeneration
Average Cost of Fuel Burned per KWh Net Gen
0.02
44
AverageBritishThermalUnitPerKilowattHourNetGeneration
Average BTU per KWh Net Generation
10,090
5,046
10,090


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: PlantName

AEP Texas's Oklaunion generating capacity output has been transferred to an affiliate at AEPTX's cost pursuant to a 20-year agreement.

 

Oklaunion Power Plant is jointly owned in the percentages shown below:

 

AEP Texas 54.69%

Public Service Company of Oklahoma (AEP Subsidiary) 15.62%

Oklahoma Municipal Power Authority 11.72%

Brownsville Public Utilities Board 17.97%

100.00%


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
1
PlantKind
Kind of Plant (Run-of-River or Storage)
2
PlantConstructionType
Plant Construction type (Conventional or Outdoor)
3
YearPlantOriginallyConstructed
Year Originally Constructed
4
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
5
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
6
NetPeakDemandOnPlant
Net Peak Demand on Plant-Megawatts (60 minutes)
7
PlantHoursConnectedToLoad
Plant Hours Connect to Load
8
NetPlantCapabilityAbstract
Net Plant Capability (in megawatts)
9
NetPlantCapabilityUnderMostFavorableOperatingConditions
(a) Under Most Favorable Oper Conditions
10
NetPlantCapabilityUnderMostAdverseOperatingConditions
(b) Under the Most Adverse Oper Conditions
11
PlantAverageNumberOfEmployees
Average Number of Employees
12
NetGenerationExcludingPlantUse
Net Generation, Exclusive of Plant Use - Kwh
13
CostOfPlantAbstract
Cost of Plant
14
CostOfLandAndLandRightsHydroelectricProduction
Land and Land Rights
15
CostOfStructuresAndImprovementsHydroelectricProduction
Structures and Improvements
16
CostOfReservoirsDamsAndWaterwaysHydroelectricProduction
Reservoirs, Dams, and Waterways
17
EquipmentCostsHydroelectricProduction
Equipment Costs
18
CostOfRoadsRailroadsAndBridgesHydroelectricProduction
Roads, Railroads, and Bridges
19
AssetRetirementCostsHydroelectricProduction
Asset Retirement Costs
20
CostOfPlant
Total cost (total 13 thru 20)
21
CostPerKilowattOfInstalledCapacity
Cost per KW of Installed Capacity (line 20 / 5)
22
ProductionExpensesAbstract
Production Expenses
23
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
24
WaterForPower
Water for Power
25
HydraulicExpenses
Hydraulic Expenses
26
ElectricExpensesHydraulicPowerGeneration
Electric Expenses
27
MiscellaneousHydraulicPowerGenerationExpenses
Misc Hydraulic Power Generation Expenses
28
RentsHydraulicPowerGeneration
Rents
29
MaintenanceSupervisionAndEngineeringHydraulicPowerGeneration
Maintenance Supervision and Engineering
30
MaintenanceOfStructuresHydraulicPowerGeneration
Maintenance of Structures
31
MaintenanceOfReservoirsDamsAndWaterways
Maintenance of Reservoirs, Dams, and Waterways
32
MaintenanceOfElectricPlantHydraulicPowerGeneration
Maintenance of Electric Plant
33
MaintenanceOfMiscellaneousHydraulicPlant
Maintenance of Misc Hydraulic Plant
34
PowerProductionExpensesHydraulicPower
Total Production Expenses (total 23 thru 33)
35
ExpensesPerNetKilowattHour
Expenses per net KWh


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
1
PlantConstructionType
Type of Plant Construction (Conventional or Outdoor)
2
YearPlantOriginallyConstructed
Year Originally Constructed
3
YearLastUnitOfPlantInstalled
Year Last Unit was Installed
4
InstalledCapacityOfPlant
Total installed cap (Gen name plate Rating in MW)
5
NetPeakDemandOnPlant
Net Peak Demaind on Plant-Megawatts (60 minutes)
6
PlantHoursConnectedToLoad
Plant Hours Connect to Load While Generating
7
NetContinuousPlantCapability
Net Plant Capability (in megawatts)
8
PlantAverageNumberOfEmployees
Average Number of Employees
9
NetGenerationExcludingPlantUse
Generation, Exclusive of Plant Use - Kwh
10
EnergyUsedForPumping
Energy Used for Pumping
11
NetOutputForLoad
Net Output for Load (line 9 - line 10) - Kwh
12
CostOfPlantAbstract
Cost of Plant
13
CostOfLandAndLandRightsPumpedStoragePlant
Land and Land Rights
14
CostOfStructuresAndImprovementsPumpedStoragePlant
Structures and Improvements
15
CostOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Reservoirs, Dams, and Waterways
16
CostOfWaterWheelsTurbinesAndGeneratorsPumpedStoragePlant
Water Wheels, Turbines, and Generators
17
CostOfAccessoryElectricEquipmentPumpedStoragePlant
Accessory Electric Equipment
18
CostOfMiscellaneousPowerPlantEquipmentPumpedStoragePlant
Miscellaneous Powerplant Equipment
19
CostOfRoadsRailroadsAndBridgesPumpedStoragePlant
Roads, Railroads, and Bridges
20
AssetRetirementCostsPumpedStoragePlant
Asset Retirement Costs
21
CostOfPlant
Total cost (total 13 thru 20)
22
CostPerKilowattOfInstalledCapacity
Cost per KW of installed cap (line 21 / 4)
23
ProductionExpensesAbstract
Production Expenses
24
OperationSupervisionAndEngineeringExpense
Operation Supervision and Engineering
25
WaterForPower
Water for Power
26
PumpedStorageExpenses
Pumped Storage Expenses
27
ElectricExpensesPumpedStoragePlant
Electric Expenses
28
MiscellaneousPumpedStoragePowerGenerationExpenses
Misc Pumped Storage Power generation Expenses
29
RentsPumpedStoragePlant
Rents
30
MaintenanceSupervisionAndEngineeringPumpedStoragePlant
Maintenance Supervision and Engineering
31
MaintenanceOfStructuresPumpedStoragePlant
Maintenance of Structures
32
MaintenanceOfReservoirsDamsAndWaterwaysPumpedStoragePlant
Maintenance of Reservoirs, Dams, and Waterways
33
MaintenanceOfElectricPlantPumpedStoragePlant
Maintenance of Electric Plant
34
MaintenanceOfMiscellaneousPumpedStoragePlant
Maintenance of Misc Pumped Storage Plant
35
PowerProductionExpenseBeforePumpingExpenses
Production Exp Before Pumping Exp (24 thru 34)
36
PumpingExpenses
Pumping Expenses
37
PowerProductionExpensesPumpedStoragePlant
Total Production Exp (total 35 and 36)
38
ExpensesPerNetKilowattHour
Expenses per KWh (line 37 / 9)
39
ExpensesPerNetKilowattHourGenerationAndPumping
Expenses per KWh of Generation and Pumping (line 37/(line 9 + line 10))


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
AEP TEXAS CENTRAL
2
TL1083 NORTH EDINBURG
RIO HONDO
345
345
15.38
1
2x795.0 ACSR
3
22.92
4
TL1098 LA PALMA
RIO HONDO
345
345
0.17
1
795.0 ACSR
5
0.13
1
795.0 ACSR
6
TL3113A BLESSING
STP
345
345
13.23
1
2x795.0 ACSR
7
(a)
TL3131 STP
WA PARRISH
345
345
14.22
1
2x795.0 ACSR
8
TL5109 LON C HILL
CPSB TIE (SAN ANTONIO)
345
345
1.81
1
2x795.0 ACSR
9
55.54
2x795.0 ACSR
10
TL5114 LON HILL
WHITEPOINT CKT #1
345
345
9.78
2
2x795.0 ACSR
11
TL5114 LON HILL
WHITEPOINT CKT #1
345
345
11
1
2x795.0 ACSR
12
TL5115 WHITEPOINT
STP
345
345
9.75
1
2x795.0 ACSR
13
87.11
1
2x795.0 ACSR
14
27
1
2x1025.4 ACCC
15
TL5138 AJO
RIO HONDO
345
345
1
1
2x1590.0 ACSR
16
65.71
1026 KCM ACCC
17
TL5138A LON HILL
NELSON SHARPE
345
345
20.81
1
2x795.0 ACSR
18
TL5138B AJO
NELSON SHARPE
345
345
0.84
1
2x1590.0 ACSR
19
36.2
2x795.0 ACSR
20
TL5138E LA PALMA
RIO HONDO CKT #2
345
345
9.75
1
2x795.0 ACSR
21
TL5139 COLETO CREEK
LON HILL
345
345
20.33
1
2x795.0 ACSR
22
59.02
23
TL5145 LON HILL
NORTH EDINBURG
345
345
0.3
1
2x1026 ACCC
24
TL5145 LON HILL
NORTH EDINBURG
345
345
111.65
1
2x1026 ACCC
25
TL3131 STP
HL&P CORRIDOR
345
345
19.35
5
2x795 ACSR
26
TL1001 BATES
GARZA
138
138
30.42
3.38
1
795.0 ACSR
27
TL1002A GARZA
ROMA TAP
138
138
16.39
1.56
1
795.0 ACSR
28
TL1002B FALCON SWITCHING
ROMA TAP
138
138
4.87
1
795.0 ACSR
29
TL1002C FALCON SWITCHING
FALCON DAM (US) CKT#1
138
138
4.5
1
4/0 ACSR
30
TL1004 BATES
NORTH EDINBURG CKT#1
138
138
22.17
1
1272.0 ACSR
31
TL1005 FALFURIAS
NORTH EDINBURG
138
138
37.8
1
795.0 ACSR
32
TL1006 JL BATES
SHARYLAND
138
138
0.31
1
1272.0 ACSS
33
TL1008 LA PALMA
WESMER
138
138
16.03
1
795.0 ACSR
34
1
795.0 ACSR
35
0.03
1
795.0 ACSS/AW
36
TL1019 FRONTERA
NORTH MCALLEN
138
138
12.8
1
1272.0 ACSR
37
0.33
2
1272.0 ACSR
38
TL1009A HARLINGEN SS
RIO HONDO
138
138
1.76
1
795.0 ACSR/AW
39
TL1009A HARLINGEN SS
RIO HONDO
138
138
12.16
1
795.0 ACSR/AW
40
TL1009B RAYMONDVILLE #2
RIO HONDO
138
138
23.89
1
795.0 ACSR
41
TL1010 LOYOLA
RAYMONDVILLE #2
138
138
31.99
1
795.0 ACSR
42
TL1011 FRONTERA
RIO GRANDE CITY
138
138
3.54
1
795.0 ACSR
43
TL1029B LA PALMA
STEWART ROAD
69
138
2.2
1
4/0 ACSR
44
20.64
795.0 ACSS
45
TL1054 HARLINGEN SS
ACSR
138
138
1.71
1
795.0 ACSR
46
TL1059 SOUTHEAST EDINBURG
MVEC PHARR
138
138
1.63
1
795.0 ACSS
47
TL1060 POLK
SOUTH MCALLEN
138
138
2.71
1
795.0 ACSS
48
TL1061 HEC
NORTH EDINBURG CKT #1
138
138
1.06
1
2x795.0 ACSR
49
TL1062 HEC
WESLACO SS
138
138
4.4
1
795.0 ACSR
50
TL1070 PORT ISABEL
PORT ISABEL
138
138
6.74
1
336.0 ACSR
51
TL1071 PORT ISABEL
PORT ISABEL
138
138
6.89
1
336.0 ACSR
52
TL1072 NORTH EDINBURG
SOUTH EDINBURG
138
138
7.3
1
795.0 ACSS
53
TL1072A HEC EXTENSION
138
138
0.8
2
795.0 ACSS
54
TL1073 STEWART ROAD
WESLACO UNIT
138
138
14.66
1
477.0 ACSR
55
795.0 ACSR
56
TL1073C SOUTH MCALLEN
STEWART ROAD
138
138
10.06
1
795.0 ACSR
57
TL1074B LA PALMA
LAURELES
138
138
9.4
1
795.0 ACSR
58
TL1074C LAURELES
PORT ISABEL
138
138
7.62
1
795.0 ACSR
59
TL1074C LAURELES
PORT ISABEL
6.87
795.0 ACSR
60
TL1075 LA PALMA
PUB LOMA ALTA
138
138
12.22
1
795.0 AAAC
61
10.14
795.0 ACSR
62
TL1076 UNION CARBIDE
PUB LOMA ALTA
138
138
1.14
1
795.0 ACSR
63
TL1077 PORT ISABEL
UNION CARBIDE BROWNSVILLE
138
138
12.85
1
477.0 ACSR
64
795.0 ACSR
65
TL1079 LA PALMA
WESLACO UNIT
138
138
5.33
1
477.0 AAC
66
TL1080 LA PALMA
MILITARY HIGHWAY
138
138
2.03
1
795.0 ACSR
67
19.01
68
TL1081 NORTH MCALLEN
SOUTH MCALLEN
138
138
4.71
1
795.0 ACSS
69
TL1082 PHARR (MVEC)
PHARR
138
138
3.61
1
795.0 ACSS
70
TL1084 POLK
SOUTH MCALLEN
138
138
3.66
1
795.0 ACSR
71
TL1085 PALMHURST TAP
138
138
1.7
1
1270.0 ACSR
72
TL1086A NORTH EDINBURG
MVG (CALPINE) GT1
138
138
0.18
1
1590.0 ACSR
73
TL1086B NORTH EDINBURG
MVG (CALPINE) GT2
138
138
0.18
1
1590.0 ACSR
74
TL1086C NORTH EDINBURG
MVG (CALPINE) ST1
138
138
0.17
1
1590.0 ACSR
75
TL1091 MILITARY HIGHWAY
UNION CARBIDE
138
138
4.75
1
795.0 ACSR
76
TL1092 NORTH EDINBURG
NORTH MCALLEN
138
138
9.6
2
795.0 ACSS
77
TL1093 NORTH MCALLEN
SOUTH MCALLEN
138
138
2.63
1
795.0 ACSS
78
0.65
79
TL1094 LAS MILPAS
SOUTH MCCALLEN
138
138
0.3
1
959 ACSS
80
TL1095 MILITARY HIGHWAY
CFE TIE
138
138
0.14
1
795.0 ACSR
81
TL1096 PORT ISABEL
PORT ISABEL
138
138
8.56
1
750.0 MCM CU
82
TL1097 LA PALMA
RIO HONDO CKT #1
138
138
10.09
1
2x795.0 ACSS
83
TL1117 FRONTERA
SOUTH MCALLEN
138
138
14.66
1
1272.0 ACSR
84
TL1117A AGAVE
SLU TAYLOR
138
138
0.15
1
1272.0 ACSR
85
TL1119 RIO GRANDE CITY
ROMA TAP
138
138
7.61
1
795.0 ACSR
86
TL1121 PHARR
POLK AVENUE
138
138
3.57
1
795.0 ACSS
87
TL1122 HEC
WESLACO SS
138
138
11.52
1
795.0 ACSR
88
TL3001 VICTORIA
MEDIO CREEK
138
138
46.56
1
336.4 ACSR
89
138
138
0.34
1
795.0 ACSR
90
138
138
0.35
1
4/0 ACSR
91
TL3146 MEDIO CREEK
LON C HILL
138
138
0.3
1
959.6 ACSS/TW
92
138
138
24.5
1
336.4 ACSR
93
138
138
1.2
1
795 ACSR
94
TL3002 COLETO
KENEDY SS
138
138
45.14
1
795.0 ACSR
95
TL3003 KENEDY SS
CPSB V.H. BRAUNIG
138
138
13.71
1
477.0 ACSR
96
TL3004 KENEDY SS
PLEASANTON
138
138
40.14
1
266.8 ACSR
97
TL3005 VICTORIA
EDNA
138
138
21.57
1
795.0 ACSR
98
TL3006 EDNA
GANADO
138
138
9.72
1
795.0 ACSR
99
TL3007 GANADO
EL CAMPO
138
138
2.09
1
795.0 AAAC
100
138
138
17.93
795.0 ACSR
101
TL3008 EL CAMPO
LANE CITY
138
138
1.43
1
795.0 AAC
102
15.81
795.0 ACSR
103
TL3009 EL CAMPO
LANE CITY
138
138
1.41
1
795.0 ACSR
104
TL3010 LOLITA
VICTORIA
138
138
23.96
1
795.0 ACSR
105
4.36
2
795.0 ACSR
106
TL3011 BLESSING
LOLITA
138
138
22.51
1
795.0 ACSR
107
TL3012 BLESSING
LANE CITY
138
138
25.5
1
477.0 ACSR
108
TL3013 DUPONT SS
VICTORIA NORTH
138
138
7.77
2
795.0 ACSR
109
TL3014 BIG THREE
DUPONT SS
138
138
3.39
1
477.0 ACSR
110
138
138
0.62
795.0 ACSR
111
TL3015 FORMOSA
LOLITA
138
138
11.84
1
795.0 ACSR
112
TL3016 JOSLIN
ALCOA (1)
138
138
1
0.09
1
1590.0 ACSR
113
TL3017 JOSLIN
ALCOA (2)
138
138
0.09
1
1
1590.0 ACSR
114
TL3018 E S JOSLIN
UNION CARBIDE
138
138
0.43
2
795.0 ACSR & 4/0
115
14.64
1
795.0 ACSR
116
3.48
2
795.0 ACSR & 4/0
117
1.92
1
795.0 ACSR
118
TL3019 AIRCO
RINCON
138
138
51.3
1
477.0 ACSR
119
TL3021 DUPONT SS
DUPONT # 1
138
138
2.09
1
795.0 AAC
120
TL3022 CELANESE
CONOCO
138
138
0.06
1
795.0 ACSR
121
TL3026 DUPONT SS
DUPONT # 2
138
138
2.08
1
795.0 AAC
122
TL3027 DUPONT SS
VICTORIA SOUTH
138
138
7.65
1
795.0 ACSR
123
TL3034 BLESSING
CELANESE BAY CITY
138
138
5.74
1
795.0 ACSR
124
TL3035 BAY CITY
CONOCO
138
138
0.84
1
795.0 ACSR
125
18.68
126
TL3036 BAY CITY
LANE CITY
138
138
0.14
1
795.0 ACSR
127
14.9
128
TL3044 SIGMOR
THREE RIVERS
138
138
0.42
1
959.6 ACSS
129
3.17
1
795 ACSR/AW
130
TL3045 SIGMOR
STEC ORANGE GROVE
138
138
1.83
1
795.0 ACSR
131
TL3046 SIGMOR
STEC SAN MIGUEL
138
138
2.41
1
1/0 ACSR
132
1.83
795.0 ACSR
133
TL3077 GOLIAD
BERCLAIR
69
138
0.02
1
477ACSR/AW
134
TL3084 VICTORIA
LCRA CUERO
138
138
4.04
1
795.0 ACSR
135
13.82
136
TL3085 VICTORIA
LCRA CUERO
138
138
10.88
1
795.0 ACSR
137
TL3111 DUPONT SS
JOSLIN
138
138
17.36
1
795.0 ACSR
138
0.95
139
TL3112 DUPONT SS
JOSLIN
138
138
0.42
1
795.0 ACSR
140
13.68
141
TL3112 DUPONT SS
JOSLIN
0.18
142
TL3113B BLESSING
CELANESE BAY CITY
138
138
5.8
1
795.0 ACSR
143
TL3114 STP PUMP TAP
STP CONSTRUCTION
138
138
6.4
1
795.0 ACSR
144
TL3115 STP CONSTRUCTION
STP RIVER PUMP
138
138
4.36
1
4/0 ACSR
145
TL3118 COLETO CREEK NORTH
VICTORIA
138
138
11.1
1
1590.0 ACSR
146
4.81
147
TL3119 COLETO CREEK SOUTH
VICTORIA
138
138
6.76
1
1590.0 ACSR
148
8.84
149
TL3122 CARBIDE SEADRIFT
VISTRON
138
138
6.13
1
477.0 ACSR
150
795.0 ACSR
151
TL3124 FORMOSA
JOSLIN
138
138
0.69
1
795.0 ACSR
152
1.84
153
TL3125 BIG THREE
VISTRON
138
138
10.52
1
477.0 ACSR
154
795.0 ACSR
155
TL3126 CELANESE
CONOCO
138
138
10.37
1
795.0 ACSR
156
TL3127 AIRCO
CARBIDE
138
138
1.43
1
477.0 ACSR
157
TL3128 FANNIN
GOLIAD
69
138
0.04
1
477 ACSR/AW
158
TL3139 CHASEFIELD TAP#2
CHASEFIELD
69
138
4.58
1
795.0 ACSR
159
TL3151 VICTORIA
(STEC) FANNIN
69
138
15.32
1
1025 ACCC
160
TL5001 KINGSVILLE
LON HILL
138
138
37.29
1
795.0 ACSR
161
138
138
0.5
1
477 ACSR
162
29.07
163
6.87
164
TL5002 KINGSVILLE
KLEBERG
138
138
1.37
1
795.0 ACSR
165
4.13
166
TL5003A KLEBERG
LOYOLA
138
138
13.5
1
795.0 ACSR
167
TL5003B LOYOLA
RAYMONDVILLE #2
138
138
26.06
1
795.0 ACSR
168
TL5004 LON HILL
STRATTON
138
138
27.8
1
795.0 ACSR
169
TL5005A DAVIS
NELSON SHARPE
138
138
10.1
1
795.0 ACSR
170
TL5005B CELANESE
NELSON SHARPE
138
138
10.18
1
795.0 ACSR
171
TL5006A FALFURIAS
KING RANCH GAS PLANT
138
138
20.48
1
795.0 ACSR
172
TL5006B KING RANCH GAS
STRATTON
138
138
15.76
1
795.0 ACSR
173
TL5007 HIGHWAY9
JAVELINA
138
138
1.5
1
1272.0 ACSR
174
TL5008 JAVELINA
WESTSIDE
138
138
1.14
1.52
1
1272.0 ACSR
175
0.13
176
TL5009 LON C HILL
WHITEPOINT
138
138
0.72
2
2x795.0 ACSR & 7
177
0.33
1
2x795.0 ACSR
178
15.21
1
2x795.0 ACSR
179
2.9
2
2x795.0 ACSR & 7
180
0.26
181
TL5011 CITGO WEST
LON HILL
138
138
6.12
1
795.0 ACSR
182
TL5013 WESTSIDE
HOLLY
138
138
2.68
1
1590.0 ACSR
183
1.28
2
1590.0 ACSR
184
TL5016 B M DAVIS
RODD FIELD
138
138
0.06
2.8
1
T2 795
185
0.06
1
1590.0 ACSR
186
TL5017 HIGHWAY 9
NUECES BAY CKT #2
138
138
0.41
0.18
1
1272.0 ACSR
187
2500.0 CU
188
TL5017 NUECES BAY
CABLE TERMINAL
138
138
0.02
1
3500kcmil XLPE
189
TL5019 HIGHWAY 9
NUECES BAY CKT #2
138
138
0.35
0.35
1
1272.0 ACSR
190
TL5020 MORRIS STREET
NUECES BAY
138
138
2.65
1
795.0 AAC
191
1.13
1
795.0 ACSR
192
1.13
1
795.0 ACSR
193
TL5021 MORRIS STREET
WESTSIDE
138
138
3.74
1
795.0 AAAC
194
1.39
2
795.0 ACSR/ 1590
195
0.14
1
477 ACSR
196
TL5022 HIGHWAY 9
NUECES BAY CKT #1
138
138
0.18
1
1272.0 ACSR
197
0.41
2500.0 CU
198
TL5022 NUECES
CABLE TERMINAL #2
138
138
0.02
1
3500kcmil XLPE
199
TL5025 AS&R
WEIL TRACT
69
138
0.06
1
795ACSR
200
TL5027 B M DAVIS
PHARAOH
138
138
0.06
2.76
1
T2 795
201
0.07
0.15
1
1590.0 ACSR
202
TL5029 ALICE
KINGSVILLE
138
138
22.48
1
477.0 ACSR
203
795.0 ACSR
204
TL5031 LON HILL
CITY OF ROBSTOWN
69
138
0.74
1
795.0 ACSR
205
TL5032 PHARAOH
AIRLINE
138
138
1.43
2
1590.0 ACSR
206
0.12
2
1590.0 ACSR
207
0.33
1
1590.0 ACSR
208
TL5058A DUPONT SS
WHITEPOINT CKT#1
138
138
0.15
8
1
795.0 ACSR
209
TL5058B DUPONT SS
WHITEPOINT CKT#2
138
138
0.15
1
795.0 ACSR
210
8
211
TL5058C NUECES BAY
WHITEPOINT CKT #1
138
138
0.46
1
795.0 ACSR
212
12.25
213
TL5061A RINCON
WHITEPOINT CKT #1
69
138
3.26
0.75
1
795.0 ACSR
214
TL5061B SINTON
WHITEPOINT
69
138
3.82
1
795.0 ACSR
215
TL5062 SINTON
WHITEPOINT
69
138
9.5
1
795.0 ACSR
216
TL5072A ARANSAS PASS
DUPONT SS
138
138
0.91
1
795.0 ACSR
217
2.29
218
TL5072B DUPONT SS
RINCON CKT#2
138
138
0.06
10.5
1
795.0 ACSR
219
TL5073 DUPONT SS
RINCON CKT#1
138
138
0.19
1
795.0 ACSR
220
10.5
221
TL5077 ARANSAS PASS
DUPONT SS
138
138
0.91
1
795.0 ACSR
222
3.96
223
TL5078 NUECES BAY
WHITEPOINT CKT #2
138
138
0.21
2.65
1
795.0 ACSR
224
7.63
225
TL5079 DUPONT SW.
PORTLAND
138
138
7.62
1
2x795.0 ACSR
226
TL5082 ARANSAS PASS
ROCKPORT
69
138
0.15
1
795ACSR/AW
227
TL5086 HIGHWAY 9
NUECES BAY
69
138
1.33
1
795.0 AAC
228
TL5087A ARCADIA
HIGHWAY 9
138
138
5.09
0.9
1
1590.0 ACSR
229
TL5087B ARCADIA
WESTSIDE
138
138
2.82
1
1590.0 ACSR
230
TL5092C QUALITECH DUMMY TO
138
138
0.46
1
795.0 ACSR
231
TL5092D NUECES BAY
UPRIVER
138
138
8
1
2x795.0 ACSR
232
TL5097 HIGHWAY 9
NUECES BAY CKT #2
138
138
2.04
1
1272.0 ACSR
233
TL5099 ARCADIA
SOUTHSIDE
138
138
2.58
0.31
1
795.0 AAC
234
795.0 ACSR
235
TL5100 LGE/GPP
REYNOLDS SHERWIN
138
138
0.5
1
795.0 ACSR
236
TL5101 HOLLY
SOUTHSIDE
138
138
0.31
1
795.0 ACSR
237
1.49
238
TL5105 DUPONT SS
ICP CKT#1
138
138
0.63
1
795.0 AAC
239
TL5106 FALFURIAS
NORTH EDINBURG
138
138
25.1
1
795.0 ACSR
240
TL5111 B M DAVIS
AIRLINE (WEST)
138
138
2.87
1
T2 795
241
2.77
2
1590.0 ACSR
242
3.05
2
1590.0 ACSR
243
1.59
1
1590.0 ACSR
244
TL5112 B M DAVIS
AIRLINE (EAST)
138
138
2.82
1
T2 795
245
1.92
2
1590.0 ACSR
246
4.78
2
1590.0 ACSR
247
0.32
1
1590.0 ACSR
248
TL5116 WEST OSO
WESTSIDE
138
138
2.42
1
1272.0 ACSR
249
TL5119 CELANESE
KLEBERG
138
138
6.09
1
795.0 ACSR
250
TL5120A DUPONT SS
OXY CHEM PP2
138
138
1.95
1
795.0 ACSR
251
TL5120B AIR LIQUID TAP
AIR LIQUID
138
138
0.01
1
795.0 ACSR
252
TL5123 DUPONT SS
ICP CKT#2
138
138
1.45
1
795.0 ACSR
253
TL5124 DUPONT SS
ICP CKT#1
138
138
0.91
1
795.0 AAC
254
TL5125 WEIL TRACT
WESTSIDE
138
138
5.11
1
1590.0 ACSR
255
TL5126 EQUISTAR
LON HILL
138
138
3.54
1
795.0 ACSR
256
TL5127 HIGHWAY 9
NUECES BAY CKT #1
138
138
2.39
1
1272.0 ACSR
257
TL5127B GILA
HIGHWAY 9 CKT #1
138
138
2.39
1
1272.0 ACSR
258
TL5127B HIGHWAY 9
NUECES BAY CKT #2
138
138
0.13
1
1272.0 ACSR
259
TL5127C HIGHWAY 9
MORRIS STREET
138
138
3.69
1
1272.0 ACSR
260
795.0 AAAC
261
TL5128 NUECES BAY
CITGO
138
138
1.06
1
795.0 AAC
262
0.67
795.0 ACSR
263
TL5135 CITGO WEST
LON HILL
138
138
0.66
1
795.0 ACSR
264
2.19
265
TL5136 DAVIS
NELSON SHARPE
138
138
12.24
1
795.0 ACSR
266
TL5141 AIRLINE
HOLLY
138
138
1.89
0.09
1
1590.0 ACSR
267
0.01
1
1590.0 ACSS
268
0.2
2
1949 ACCC
269
TL5142 RODD FIELD
CABANISS
138
138
1
1590.0 ACSR/AW
270
1.47
1
1590.0 ACSR/AW
271
2.8
1
1590 ACSS
272
1.8
1
1949 ACCC
273
TL5143A CABANISS
WESTSIDE
138
138
1
1590.0 ACSR/AW
274
1
1590.0 ACSR/AW
275
TL5143 CABANISS
WESTSIDE
138
138
1.19
1
1590 ACSS
276
0.46
1
1590 ACCC
277
TL5143B EQUISTAR
WESTSIDE
138
138
0.46
1
1590.0 ACSR
278
TL5149 LON C HILL
ORANGE GROVE
138
138
2.1
1
795.0 ACSR
279
138
138
11.48
1020 ACCC
280
138
138
11.27
2
1026 ACCC
281
TL5150 HOMEPORT
INGLESIDE
138
138
3.69
1
795.0 AAC
282
795.0 ACSR
283
TL5155 DUPONT SS
GPP CKT#2
138
138
0.04
1.29
1
2x795.0 ACSR
284
TL5156 DUPONT SS
GPP CKT#1
138
138
1.29
1
2x795.0 ACSR
285
TL5160 WHITEPOINT
DUPONT SW
138
138
1.34
2
795ACSS
286
0.81
2
795 ACSR/AW
287
TL5165 RINCON
WHITEPOINT CKT #2
138
138
3.14
1
795.0 ACSR
288
4.56
289
TL5166 DUPONT SS
WHITEPOINT CKT#3
138
138
5.2
1
2x795.0 ACSR
290
TL5178 JARDIN SUBSTATION
JARDIN SUBSTATION
138
138
0.03
1
795.0 ACSR
291
TL5179 LA PALMA
PALO ALTO (PUB)
138
138
292
TL5187 HECKER
EXTENSION #1
138
138
0.52
2
795.0 ACSR
293
TL5188 BUNSEN
EXTENSION
138
138
0.73
2
959.6 ACSS
294
TL5194 KEPLER
EF 90
69
138
0.04
1
477ACSR/AW
295
TL5195 TORTUGA
M&G 138kV EXTENSION
138
138
0.4
1
477 ACSR
296
TL5199 PHARR 138kV LOOP
138
138
2.2
2
959.6 ACSS/TW SUW
297
TL5202 HECKER
ALPINE
138
138
0.06
2
795.0 ACSR
298
TL5203 HECKER
CHENIERE (CUSTOMER STATION)
138
138
0.09
2
1590 ACSR Falcon
299
TL5205 CRYSTAL CITY
LA PRYOR EXTENTION
69
138
0.04
1
795ACSR
300
TL5206 MARCONI
SAN ROMAN
138
138
0.7
1
959ACSS/TW
301
TL5207 MELON CREEK EXTENSIO
138
138
0.82
2
795 ACSS/AW
302
TL5208 LA PRYOR
UVALDE EXTENTION
69
138
0.06
1
795ACSR
303
TEXISLE
138
138
0.5
1
477.0 ACSR
304
TL5222 HARLINGEN SS
RAYMONDVILLE #2
69
138
23.06
1
959.6 ACSS/TW
305
TL5226 JOSLIN POI (IPP)
138
138
0.03
1
795ACSR
306
TL5231 BISHOP
STRATTON
69
138
4.8
1
795 ACSS/AW
307
0.03
1
795 ACSS/AW
308
TL5242 CARANCAHUA
PALACIOS
69
138
0.08
1
795 ACSS/AW
309
TL5243 POINT COMFORT
CARANCAHUA
69
138
0.06
1
795 ACSS/AW
310
TL5248 COY CITY
THREE RIVERS
69
138
6.98
1
795 ACSS
311
TL5249 SEAWALL
PORT ARANSAS
69
138
8.02
1
795 ACSS/AW
312
0.1
1
795 ACSS/AW
313
TL5251 GOLIAD
FANNIN
69
138
5.1
1
795 ACSS/AW
314
TL5253 HEARD TAP
REFUGIO
69
138
2.65
1
795 ACSS
315
TL5254 WOODSBORO
HEARD TAP
69
138
3.33
1
795 ACSS/AW
316
TL5258 PHARR BUS TIE #1
138
138
0.18
1
795 ACSS
317
TL5259 PHARR BUS TIE #2
138
138
0.11
1
795 ACSS
318
TL5260 RINCON
GREGORY
69
138
3.04
1
795 ACSS/AW
319
TL7001 LAREDO
MILO ROAD
138
138
8.81
2.83
1
795.0 ACSR
320
TL7003 CONOCO TAP
CONOCO
138
138
4.8
1
4/0 ACSR
321
TL7005A EAGLE PASS
ESCONDIDO CKT#2
138
138
1.37
1
336.0 ACSR
322
TL7005B ESCONDIDO
HAMILTON ROAD
138
138
10.13
1
336.0 ACSR
323
TL7006 EAGLE PASS HYDRO TAP
EAGLE PASS HYDRO
138
138
0.31
1
336.0 ACSR
324
TL7007 ESCONDIDO
HAMILTON ROAD
138
138
2.38
1
336.0 ACSR
325
TL7008 HAMILTON ROAD PST
SONORA
138
138
66.85
1
477.0 ACSR
326
138
138
0.3
1
959.6 ACSS/TW
327
TL7009 ASHERTON
WEST BATESVILLE
138
138
36.09
1
336.0 ACSR
328
TL7010 PLEASANTON
CPSB LEON CREEK
138
138
15.4
1
1020.0 ACCC/TW
329
TL7011 PLEASANTON
BIGFOOT
138
138
29.83
1
336.4 ACSR
330
TL7012A MOORE
MEC DOWNIE
138
138
41.27
1
336.4 ACSR
331
TL7012B UVALDE
MEC DOWNIE
138
138
9.34
1
336.4 ACSR
332
TL7016 FALFURRIAS
LOBO
138
138
26.96
1
2x795.0 ACSS
333
795.0 ACSR
334
TL7017 BRUNI
CRESTONIO
138
138
14.8
1
795.0 ACSR
335
TL7018 LAREDO PLANT
DEL MAR
138
138
2.67
1
795.0 ACSR/AW
336
TL7019 ZAPATA
RANDADO
138
138
22.2
1
4/0 ACSR
337
TL7020A FALCON SWITCHING
FALCON DAM (US) CKT#2
138
138
4.5
1
4/0 ACSR
338
TL7020B FALCON SWITCHING
ZAPATA
138
138
25.8
3.95
1
795.0 ACSR
339
TL7021C LAREDO POWER PLANT
LAREDO VFT SOUTH
138
138
0.24
1
795.0 ACSR
340
TL7025 HEIGHTS
LAREDO CKT #1
138
138
4.4
1
795.0 AAAC
341
TL7025B HEIGHTS
LAREDO CKT #2
138
138
5.19
1
795.0 AAAC
342
TL7026 FREER
LOBO
69
138
1.09
1
2x795.0 ACSS
343
48.38
4/0 ACSR
344
TL7030 ENCINAL
COTULLA
138
138
29.09
1
795.0 ACSR
345
TL7046 ASHERTON
DILLEY SS
138
138
15.98
1
795.0 ACSR
346
TL7047 ASHERTON
DILLEY SS
138
138
21.8
1
795.0 ACSR
347
TL7048 COTULLA
DILLEY SS
138
138
16.15
1.17
1
795.0 ACSR
348
TL7065 HAMILTON ROAD
PICACHO CKT#1
138
138
8.67
1
4/0 ACSR
349
TL7066 PICACHO
AMISTAD HYDRO
138
138
6.4
1
4/0 ACSR
350
TL7067 HAMILTON ROAD
PICACHO CKT#2
138
138
1.45
1
4/0 ACSR
351
1.07
352
TL7068 HAMILTON ROAD
PICACHO CKT#2
138
138
1.29
1
4/0 ACSR
353
1.53
354
TL7069 HAMILTON ROAD
PICACHO CKT#2
138
138
0.44
1
4/0 ACSR
355
2.65
356
TL7079 BIGFOOT
MOORE
138
138
6.06
1
336.4 ACSR
357
TL7081 EAGLE PASS
CFE PIEDRAS NEGRAS
138
138
1.33
1
477.0 ACSR
358
TL7082 ESCONDIDO
HAMILTON ROAD
138
138
41.21
1
336.0 ACSR
359
TL7086 UVALDE
WEST BATESVILLE
138
138
20.61
1
336.0 ACSR
360
TL7087 WEST BATESVILLE
MEC BATESVILLE
138
138
9.36
1
795.0 ACSR
361
TL7088 DILLEY SS
STEC SAN MIGUEL
138
138
47.54
1
795.0 ACSR
362
363
TL7091 PICACHO
AMISTAD HYDRO
138
138
1.91
1
336.0 ACSR
364
TL7092B EAGLE PASS
ESCONDIDO CKT#1
138
138
0.32
1
4/0 ACSR
365
1.13
795.0 ACSR
366
TL7102 RIO BRAVO
ZAPATA
138
138
27.48
3.1
1
795 ACSR
367
0.23
1
4/0 ACSR
368
TL7105 WORMSER
RIO BRAVO
138
138
0.46
1
795.0 ACSR
369
TL7111 UNIVERSITY
WORMSER
138
138
1.74
1
795 ACSR
370
2.68
2
795 ACSR
371
TL7114 ENCINAL
WORMSER
138
138
40.77
1
795 ACSR
372
8.43
2
795 ACSR
373
0.27
1
795 ACSR/AW
374
TL7115B UNIVERSITY
WORMSER
138
138
9.99
1
795.0 ACSR
375
TL7117 ASHERTON
NORTH LAREDO
138
138
6.95
1
366.4 ACSR
376
56.69
795.0 ACSR
377
TL7123 SIERRA VISTA
WORMSER
138
138
1.11
1
795.0 ACSR
378
138
138
1.76
2
795.0 ACSR
379
TL7124 EL GATO
GOOLIE/SOUIX RD
138
138
5.3
1
795.0 ACSS
380
TL7125 SOUTH MCALLEN
STEWART ROAD
138
138
3.7
1
1590 ACSS
381
2.14
2
795.0 ACSS
382
TL7125 SOUTH MCALLEN
STEWART ROAD
138
138
5.96
1
795.0 ACSS
383
TL7138 PILONCILLO
PRANCH #1
138
138
0.06
1
795 ACSR
384
TL7141 BRACKETVILLE
BUS TIE #1
138
138
0.11
1
795 ACSS
385
TL7142 LAREDO STATCOM 138kV
138
138
0.1
1
1026 ACCC/TW
386
TL7144 ASHERTON
CARRIZO SPRINGS
69
138
8.36
1
959.6ACSS/TW
387
TL5224 BRACKETVILLE
BUS TIE #2
138
138
0.13
1
795 ACSS
388
TL5185 KENEDY SWITCHING STA
TULETA
138
138
19.33
2
959 ACSR/TW
389
TL5180 KENEDY SWITCHING STA
PETTUS
138
138
19.33
2
959 ACSR/TW
390
TL5261 BRACKETTVILLE
ESCONDIDO
138
138
391
TL5209 BONILLA
LADEKIDDE
345
345
392
TL5264 LA PALMA SVC
138KV BUS TIE #1
138
138
393
TL5265 LA PALMA SVC
138KV BUS TIE #2
138
138
394
69 KV (148 LINES)
69
69
966
47.18
395
AEP TEXAS NORTH
396
TL125A ABILENE MULBERRY
BLUFF CREEK SS
345
345
26.5
0.42
1
2x795.0 ACSR
397
TL125B BLUFF CREEK SS
SAN ANGELO RED CREEK
345
345
0.42
1
2x795.0 ACSR
398
49.56
399
TL126 ABILENE MULBERRY
OKLAUNION
345
345
115.65
1
2x795.0 ACSR
400
TL131 OKLAUNION
TU FISHER ROAD
345
345
30.14
1
2x795.0 ACSR
401
TL324 OKLAUNION DC TIE
DC TERMINAL NORTH (SPP)
345
345
0.02
1
1926.9KCM ACSR
402
TL325 OKLAUNION DC TIE
DC TERMINAL SOUTH (ERC)
345
345
0.02
1
1926.9KCM ACSR
403
TL001 ABILENE SOUTH
PUTNAM
138
138
3.13
1
4/0 ACSR
404
32.16
477.0 ACSR
405
TL013 PUTNAM-MORAN
THROCKMORTON - MUNDAY
69
138
13.3
1
795 ACSS/AW
406
TL028 ABILENE NORTHWEST
ANSON (TAP FORT PHANTOM PUM
69
138
1.63
1
795 ACSS/AW
407
TL031 SANTA ANNA
BROWNWOOD
138
138
7.29
1
795.0 ACSR
408
TL033 EDEN
YELLOWJACKET
69
138
0.11
1
795 ACSS
409
TL034 MASON SWITCHING
YELLOWJACKET
69
138
0.23
0.8
1
795 ACSS
410
TL048 MCCAMEY - MCELROY
CRANE GULF 1&2
69
138
0.32
1
795 ACSS
411
TL050 FORT STOCKTON PLANT
RIO PECOS
138
138
37.48
1
477.0 ACSR
412
TL051 EAST MUNDAY
PADUCAH CLARE STREET
138
138
3.2
1
477.0 ACSR
413
59.08
414
TL064A EAST MUNDAY
LAKE PAULINE
138
138
56.97
1
2x4/0 ACSR
415
TL064B EAST MUNDAY
PAINT CREEK WEST#1
138
138
25.96
1
397.0 ACSR
416
TL066A FORT PHANTOM
PAINT CREEK
138
138
38.73
1
1272.0 AAC
417
0.48
477.0 ACSR
418
TL066B CALIFORNIA CREEK TAP
CALIFORNIA CREEK
138
138
0.02
1
4/0 ACSR
419
TL070 ABILENE NORTHWEST
OAK CREEK
138
138
47.01
1
397.0 ACSR
420
5.21
1
795.0 ACSR
421
TL072 ABILENE NORTHWEST
PAINT CREEK
138
138
44.22
1
477.0 ACSR
422
TL077 BALLINGER
OAK CREEK
138
138
30.85
1
397.0 ACSR
423
477.0 ACSR
424
TL079A NICOLE
SAN ANGELO RED CREEK
138
138
3.21
2
2x795.0 ACSS
425
33.77
397.0 ACSR
426
477.0 ACSR
427
TL079B NORTH SAN ANGELO
SAN ANGELO RED CREEK
138
138
0.64
1
795.0 ACSR
428
8.96
429
TL079C SAN ANGELO CONCHO
SAN ANGELO RED CREEK
138
138
2.07
1
795.0 ACSR
430
7.66
431
TL080 ALPINE
FORT STOCKTON
69
138
0.15
1
477ACSR
432
TL082A BLUFF CREEK SS
NICOLE
138
138
1
2x795.0 ACSS
433
TL082B ABILENE SOUTH
BLUFF CREEK SS
138
138
0.43
1.68
1
1020.0 ACCC/TW
434
17.24
2x795.0 ACSS
435
TL082C NICOLE
OAK CREEK
138
138
2.42
1
2x795.0 ACSS
436
437
TL083A ABILENE SOUTH
EAST ABILENE
138
138
3.82
1
795.0 ACSR
438
5.63
439
TL083B ABILENE ELM CREEK
ABILENE NORTHWEST CKT#2
138
138
0.53
1
795.0 ACSR
440
2.54
441
TL083C ABILENE NORTHWEST
FORT PHANTOM
138
138
10.96
0.5
1
1272.0 AAC
442
2x795.0 ACSR
443
TL083D ABILENE SOUTH
FORT PHANTOM
138
138
2.07
1
1272.0 AAC
444
15.61
1272.0 ACSS
445
0.49
2x477.0 ACSR
446
795.0 ACSR
447
TL083E EAST ABILENE
FORT PHANTOM
138
138
9.54
0.39
1
1272.0 AAC
448
795.0 ACSR
449
TL083F ABILENE ELM CREEK
ABILENE SOUTH CKT#2
138
138
3.69
1
795.0 ACSR
450
6.61
451
TL083G EAST ABILENE TAP
EAST ABILENE
138
138
2.04
1
2x477.0 ACSR
452
795.0 ACSR
453
TL083G TEC SHARP TAP
TEC SHARP
138
138
2.04
1
2x477.0 ACSR
454
795.0 ACSR
455
TL084A SAN ANGELO CONCHO
SAN ANGELO POWER STATION
138
138
5.93
1
477.0 ACSR
456
0.16
457
0.12
1590 ACSR
458
TL084B SOUTH ANGELO TAP
SOUTH ANGELO
138
138
1
1
4/0 ACSR
459
TL085 SAN ANGELO
BIG LAKE
138
138
9.67
1
477.0 ACSR
460
54.9
795.0 ACSR
461
TL086 BIG LAKE
NORTH MCCAMEY
138
138
36.34
1
477.0 ACSR
462
10.3
1
956.6 ACSS
463
0.15
1
795 ACSS
464
TL087 LAKE PAULINE
VERNON CKT #2
138
138
24.36
1
477.0 ACSR
465
TL088A SAN ANGELO POWER
SAN ANGELO RED CREEK
138
138
1.29
1
477.0 ACSR
466
17.33
467
TL088B BALLINGER
SAN ANGELO RED CREEK
138
138
3.07
1
477.0 ACSR
468
29.48
469
TL089 HAMILTON ROAD PST
SONORA
138
138
21.84
1
477.0 ACSR
470
LOAD
471
TL089A ELDORADO LIVE OAK
SAN ANGELO POWER STATION
138
138
38.23
1
477.0 ACSR
472
TL089B ELDORADO LIVE OAK
SONORA CKT#2
138
138
22.07
1
477.0 ACSR
473
TL090 ASPERMONT
PAINT CREEK
138
138
39.74
1
477.0 ACSR
474
TL092A LCRA CRANE
RIO PECOS CKT #1
138
138
0.82
1
636.0 ACSR
475
22.83
795.0 ACSR
476
TL092B TEXAS NEW MEXICO TAP
CRANE TAP #2
69
138
0.1
1
4/0 ACSR
477
TL093 SAN ANGELO POWER
YELLOWJACKET
138
138
0.85
1
477.0 ACSR
478
54.31
795 ACSS
479
TL094 PUTNAM
LEON CKT #2
138
138
21.93
1
4/0 ACSR
480
477.0 ACSR
481
TL095 SAN ANGELO COLLEGE
SAN ANGELO POWER STATION
138
138
2.75
1
795.0 ACSR
482
HILLS
483
TL097 EAST MUNDAY
PAINT CREEK EAST#2
138
138
26.67
1
477.0 ACSR
484
TL100 BARRILLA JUNCTION
FORT STOCKTON PLANT
138
138
25.39
1
477.0 ACSR
485
TL111 ASPERMONT
SPUR
138
138
10.19
1
477.0 ACSR
486
35.36
487
TL113 ALAMITO CREEK
BARRILLA JUNCTION
138
138
0.32
1
477.0 ACSR
488
66.99
489
TL117 NORTH SAN ANGELO
SAN ANGELO COLLEGE HILLS
138
138
2.1
1
795.0 ACSR
490
6.48
491
TL120A CEDAR HILL
OAK CREEK
138
138
26.26
1
4/0 ACSR
492
138
138
0.09
1
959.6 ACSS
493
TL120B FORT CHADBOURNE TAP
FORT CHADBOURNE
138
138
0.02
1
4/0 ACSR
494
TL122 ABILENE MULBERRY
ABILENE NORTHWEST
138
138
2.59
1
1272.0 AAC
495
1272.0 ACSR
496
TL123 MENARD
FORT MASON (LCRA)
138
138
1.05
1
477.0 ACSR
497
37.27
795 ACSS
498
TL124 FORT MASON (LCRA)
GILLESPIE COUNTY LINE
138
138
22.87
1
477.0 ACSR
499
0.05
1
795 ACSS
500
TL127A BALLINGER
SANTA ANNA CKT #1
138
138
0.56
1
477.0 ACSR
501
37.82
502
TL127B EAST COLEMAN TAP
EAST COLEMAN
138
138
2.98
1
477.0 ACSR
503
TL128 OKLAUNION
VERNON
138
138
2.59
1
795.0 ACSR
504
6.72
505
TL129 ABILENE ELM CREEK
ABILENE MULBERRY CREEK
138
138
0.52
1
1272.0 AAC
506
5.19
507
TL133 OKLAUNION
SOUTHWEST VERNON
138
138
6.98
1
795.0 ACSR
508
0.48
1
795.0 ACSR
509
TL136 SPUR
SUN
138
138
0.31
1
795.0 ACSR
510
17.48
511
TL138 PADUCAH CLARE STREET
WEST CHILDRESS
138
138
1.87
1
477.0 ACSR
512
29.55
513
TL140 SOLSTICE
YUCCA DRIVE (ONCOR)
138
138
37.27
1
477.0 ACSR
514
0.49
1
477 ACSR
515
0.57
1
2-795 ACSR
516
TL141 FRIEND RANCH
SONORA
138
138
32.85
1
477.0 ACSR
517
TL204 STERLING-SUN JAMESON
ROBERT LEE - STERLING
69
138
0.08
1
959.6ACSS/TW
518
TL242 BIG LAKE
FRIEND RANCH
138
138
39.63
1
477.0 ACSR
519
138
138
0.4
2
959 ACSR/TW
520
TL243 LCRA NORTH MCCAMEY
NORTH MCCAMEY
138
138
0.19
1
795.0 ACSR
521
TL310 BLUFF CREEK
BUFFALO GAP
138
138
2.04
1
2x795.0 ACSS
522
TL319 GONZALES
ACACIA
69
138
2.4
1
795.0 ACSR
523
TL321 ESMERALDA
YUCCA
138
138
14.8
1
4/0ACSR
524
TL322 SAN ANGELO
RUSTHILL #1
69
138
0.02
1
1590 ACSR
525
TL323 SAN ANGELO CONCHO
RUSTHILL #2
138
138
0.17
1
1590 ACSR
526
TL327 SANTA RITA
EXTENSION
69
138
0.17
1
2/0 ACSR
527
TL353 DINNY
WEST YATES
69
138
3.19
1
959 ACSS/TW
528
TL329 BARRILLA JUNCTION
SOLSTICE
138
138
0.2
1
2x956.6 ACSS
529
TL331 N BRADY
BRADY CITY
69
138
0.9
2
795
530
TL333 ABILENE NORTHWEST
ELY
69
138
8.25
1
477ACSR
531
TL334 ALAMITO CREEK
MARFA
69
138
0.58
1
959 ACSS/TW
532
TL335 MUNDAY
POINTER
69
138
5.75
1
959 ACSR/TW
533
TL337 CASSAVA
YUCCA
138
138
11.9
1
397ACSR/T2
534
TL338 SOLSTICE
HOVEY
138
138
0.14
1
477 ACSR
535
138
138
0.1
1
477 ACSR
536
TL339 HENDRICK 138KV
HAIRPIN
138
138
0.68
2
795ACSS
537
TL340 ALBANY FOUNDRY
HULLTOWN
69
138
9.5
1
795 ACSS/AW
538
TL342 LOTEBUSH
ENSTOR HACBERRY DRAW
138
138
0.04
1
477 ACSR
539
TL343 BISON
POWELL FIELD 138KV TAP
69
138
6.8
1
4/0ACSR
540
TL345 ALBANY
FORT GRIFFIN
69
138
0.86
1
795 ACSS/AW
541
TL346 BIG LAKE
SAN ANGELO MATHIS FIELD
69
138
16.5
1
795 ACSS
542
TL348 CROWELL
MUNDAY
69
138
3.8
1
4/0 ACSR
543
12.2
1
2x477 ACSR
544
TL349 JAYTAN
ROTAN
69
138
21.25
1
795 ACSS/TW
545
TL350 ALPINE
BARRILLA JUNCTION
69
138
49.34
1
795 ACSS
546
TL351 ABILENE SOUTH
SAWGRASS
69
138
1.95
1
795 ACSS
547
TL352 CACTUS
FORT LANCASTER
69
138
9.2
1
956.6 ACSS
548
TL354 QUAINT 138kV EXTENSIO
69
138
0.27
2
795 ACSS/AW
549
TL356 BRONCO 138KV
EXTENSION
69
138
0.29
1
795 ACSS
550
TL358 FORT GRIFFIN
RAINEY CREEK
69
138
0.37
1
795 ACSS/AW
551
TL359 ALBANY FOUNDRY
FORT GRIFFIN
69
138
0.14
1
795 ACSS
552
TL363 ABILENE NORTHWEST
ANSON
69
138
1.38
1
795 ACSS
553
1.74
1
795 ACSS/AW
554
TL365 ABILENE NORTHWEST
ELM CREEK
69
138
3.1
1
795 ACSS
555
TL366 HENDRICK POI (OCI)
138
138
0.03
1
477ACSR
556
TL373 DERRICK
OWLS
69
138
4.24
1
795 ACSS
557
TL387 PECOS VALLEY
RIO PECOS
69
138
16.49
1
795 ACSS
558
TL400 CEDAR HILL
ROBERT LEE
69
138
12.6
1
795 ACSS
559
TL402 BRONCO
LASSO
69
138
0.1
1
795 ACSS
560
TL412 LOTEBUSH
BROZOS MIDSTREAM
138
138
0.04
1
959.6 ACSS/TW
561
TL413 LOTEBUSH
ARROWHEAD
138
138
0.04
1
1926.9 ACSR/TW
562
TL414 LOTEBUSH
NW COYANOSA
138
138
0.06
2
959.6 ACSS/TW
563
TL420 MERTZON
MATHIS FIELD
69
138
23.6
1
795 ACSS
564
TL407 SOLSTICE
BAKERSFIELD
345
345
565
69kV (173 LINES)
69
69
2,139.59
45.12
VARIOUS
566
Line costs and expense are
not available by individual
567
transmission line.
Totals shown in col j-p
88,263,851
1,659,412,634
1,747,676,485
339,705
11,550,021
11,889,726
36
8,145.58
180.18
501
88,263,851
1,659,412,634
1,747,676,485
339,705
11,550,021
11,889,726


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: TransmissionLineStartPoint

Jointly Owned Transmission Line:

 

AEP Texas owns 20.82% of transmission lines in the STP Corridor.


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
AEP TEXAS CENTRAL
COMPANY
2
TL5258 PHARR BUS TIE #1
0.18
1
1
138
671,850
102,833
774,683
3
TL5259 PHARR BUS TIE #2
0.11
1
1
138
511,358
120,484
631,842
4
AEP TEXAS NORTH
COMPANY
5
TL342 LOTEBUSH
ENSTOR HACBERRY DRAW
0.04
1
1
138
13,947
625,890
42,065
681,902
6
TL412 LOTEBUSH
BROZOS MIDSTREAM
0.04
1
1
138
212,700
17,204
229,904
7
TL413 LOTEBUSH
ARROWHEAD
0.04
1
1
138
288,140
24,332
312,472
8
TL414 LOTEBUSH
NW COYANOSA
0.06
2
2
138
453,426
35,949
489,375
44
TOTAL
0.47
7
7
13,947
2,763,364
342,867
3,120,178


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
WESLACO UNIT - TX
D
138
12.47
90
2
2
WESLACO UNIT - TX
D
138
STATCAP
1
29
3
WESMER - TX
D
138
12.47
56
2
4
WESMER - TX
D
12
STATCAP
2
10
5
WEST HARLINGEN - TX
D
69
12.47
56
2
6
WEST HARLINGEN - TX
D
12
STATCAP
3
11
7
WEST MCALLEN - TX
D
138
12.47
90
2
8
WEST MCALLEN - TX
D
12
STATCAP
4
19
9
WEST OSO - TX
D
138
12.47
28
1
10
WESTSIDE SW - TX
T
138
STATCAP
2
58
11
WHITE POINT - TX
T
138
69
12
93
1
12
WHITE POINT - TX
T
345
138
13.8
480
1
13
WHITE POINT - TX
T
138
AIR CORE REACTOR
6
86
14
WOODSBORO - TX
D
69
12.47
8
1
15
WOODSBORO - TX
D
12
STATCAP
1
2
16
WOOLDRIDGE - TX
D
138
12.47
28
1
17
WORMSER ROAD SW - TX
T
138
STATCAP
2
14
18
YORKTOWN - TX
D
138
13.09
25
2
19
ZACATE CREEK - TX
D
138
12.47
40
1
20
ZAPATA - TX
D
138
12.47
25
1
21
ZAPATA - TX
D
138
13.09
25
2
22
ABILENE AILEEN - TX
D
138
13.09
0.5
28
1
23
ABILENE COUNTRY CLUB - TX
D
138
13.09
20
1
24
ABILENE EAST - TX
T
138
13.09
28
1
25
ABILENE EAST - TX
T
138
69
7.67
75
1
26
ABILENE EAST - TX
T
138
69.3
13.2
63
1
27
ABILENE INDUSTRIAL PARK - TX
D
138
13.09
56
2
28
ABILENE NORTHWEST - TX
T
138
69
11.2
92
1
29
ABILENE NORTHWEST - TX
T
138
69.5
36.2
90
1
30
ABILENE OIL MILL - TX
D
69
13
25
1
31
ABILENE ONYX REA - TX
D
69
13
12
3
32
ABILENE POWER PLANT - TX
T
69
7.56
13
2
33
ABILENE POWER PLANT - TX
T
69
7.56
2.4
7
1
34
ABILENE POWER PLANT - TX
T
69
13.09
1
35
ABILENE SOUTH - TX
T
138
70.5
13.09
180
2
36
ABILENE SOUTH - TX
T
138
STATCAP
3
86
37
ACME BESTWALL - TX
D
69
13
5
1
38
AFTON (WT) - TX
D
69
7.2
3
3
39
ALBANY (WT) - TX
D
69
13
10
1
40
ALBANY FOUNDRY - TX
D
69
13
25
1
41
ALBANY HUBBARD BOOSTER #1 WCT - TX
D
2.4
3
42
ALBANY HUBBARD BOOSTER #1 WCT - TX
D
69
2.52
4
3
43
ALBANY HUBBARD BOOSTER #2 WCT - TX
D
2.4
0.48
3
44
ALBANY HUBBARD BOOSTER #2 WCT - TX
D
69
2.52
4
3
45
ALPINE - TX
D
69
13
40
4
46
ANSON - TX
D
69
13.09
9
1
47
ANSON REA - TX
D
69
13
5
1
48
ARROTT - TX
D
69
12.5
2
3
49
ASPERMONT - TX
T
138
69
14.4
63
1
50
ASPERMONT - TX
T
69
13
9
1
51
ASPERMONT CONTINENTAL OIL CO. - TX
D
69
13
4
1
52
ATKINSON RANCH - TX
D
69
2.4
2
53
BAIRD CITY - TX
D
69
13
5
1
54
BALLINGER - TX
T
138
13.09
25
1
55
BALLINGER - TX
T
138
66
13.8
63
1
56
BALLINGER HUMBLE - TX
D
69
2.4
1
3
57
BARNHART - TX
D
69
13.09
9
1
58
BARNHART - TX
D
69
STATCAP
1
4
59
BARRILLA JUNCTION - TX
T
138
69
6.57
63
1
60
BARRILLA JUNCTION - TX
T
69
12.4
1
61
BENJAMIN - TX
D
69
12.4
2
2
62
BENJAMIN - TX
D
69
13
1
1
63
BIG LAKE - TX
T
12
4.1
2
3
64
BIG LAKE - TX
T
69
13
10
3
65
BIG LAKE - TX
T
138
69
2.4
50
1
66
BIG LAKE - TX
T
138
69
5.39
50
1
67
BIG LAKE - PHILLIPS PUMP - TX
D
69
12.5
2
3
68
BLUFFS - TX
D
138
12.47
25
1
69
BOBCAT HILLS - TX
D
69
12.47
5
1
70
BOND ROAD - TX
D
7.62
13.09
9
1
71
BRADSHAW - TX
D
69
12.4
1
3
72
BRADY CITY (MUNICIPAL INTERCON - TX
D
69
13
7.62
11
1
73
BRADY CITY (MUNICIPAL INTERCON - TX
D
STATCAP
1
6
74
BRONTE - TX
D
69
12.47
6
1
75
BRONTE - TX
D
STATCAP
2
76
BRONTE (AMBASSADOR) - TX
D
69
13
2
3
77
BRONTE ATLANTIC - TX
T
69
12.5
2
1
78
BRYANT RANCH - TX
D
69
12.47
1
3
79
BUSH KNOB (THROCKMORTON) - TX
D
69
7.56
8
3
80
CANYON ROCK - TX
D
138
13.09
15
1
81
CASSAVA - TX
T
138
70.5
13.09
90
1
82
CEDAR GAP - TX
D
69
13
6
1
83
CEDAR HILL - TX
T
138
70.5
13.09
90
1
84
CEDAR HILL - TX
T
69
STATCAP
1
12
85
CHERRY CREEK (WT) - TX
D
69
13
5
1
86
CHILDRESS - TX
T
69
12.47
12
1
87
CHILDRESS 20TH ST SUB CHILDRES - TX
D
69
13
16
1
88
CHILDRESS WEST - TX
T
138
69
2.4
50
1
89
CHILLICOTHE - TX
D
69
13.09
11
3
90
CHINATI - TX
T
138
STATCAP
1
91
CHRISTOVAL - TX
D
69
13
6
1
92
CISCO - TX
D
138
13.09
24
2
93
CLAIRMONT SUN OIL CO. - TX
D
69
7.2
2
3
94
CLYDE - TX
D
69
13
25
1
95
CLYDE - TX
D
69
STATCAP
1
12
96
CLYDE MAGNOLIA PUMP PIPELINE - TX
D
69
2.5
6
1
97
COLEMAN EAST - TX
D
138
13.09
25
1
98
CORINTH - TX
D
69
7.2
1
3
99
CRANE (TESCO INTER) - TX
T
138
70.5
13.09
130
1
100
CRANE (TESCO INTER) - TX
T
138
STATCAP
1
57
101
CRANE COUNTY AIRPORT - TX
D
69
4.1
11
1
102
CROCKETT HEIGHTS (OZONA) - TX
D
69
12
2
3
103
CROSS PLAINS - TX
D
69
13.09
8
1
104
CROWELL - TX
T
69
13
6
1
105
DISCOVERY CANYON - TX
D
69
12.5
5
3
106
DUNE FIELD - TX
D
69
13
10
3
107
DYESS AFB #1 - TX
D
69
7.56
2.4
6
2
108
DYESS AFB #1 - TX
D
69
13
2.4
3
1
109
DYESS AFB #2 - TX
D
69
13
16
1
110
DYESS AFB #3 - TX
D
69
7.56
2.4
19
3
111
EDEN - TX
T
69
13
5
3
112
EDITH HUMBLE - TX
D
69
13.09
3
1
113
ELDORADO - TX
D
69
13
8
3
114
ELDORADO CITIES SERVICE CO. - TX
D
69
12
1
2
115
ELDORADO CITIES SERVICE CO. - TX
D
69
12.5
1
1
116
ELDORADO LIVE OAK SUB. - TX
T
138
69
6.6
63
1
117
ELDORADO LIVE OAK SUB. - TX
T
138
69
7
50
1
118
ELDORADO LIVE OAK SUB. - TX
T
STATCAP
1
12
119
ELDORADO SHELL BAILEY - TX
D
69
4.36
8
1
120
ELM CREEK - TX
T
138
69
8.55
92
1
121
ELM CREEK - TX
T
138
13.09
48
2
122
ELMDALE - TX
D
69
13
9
1
123
EOLA - TX
D
69
13
4
3
124
ESPY WELLS - TX
D
69
7.2
1
125
FLOMOT - TX
D
69
13
2
3
126
FORT DAVIS - TX
D
69
12.4
8
3
127
FORT DAVIS - TX
D
69
STATCAP
1
4
128
FORT LANCASTER - TX
T
138
69
12.47
50
1
129
FORT MCKAVITT - TX
D
69
2.4
2
3
130
FORT STOCKTON PLANT - TX
T
138
69
8.88
63
1
131
FORT STOCKTON SW STATION - TX
T
69
7.2
1
132
FREDERICKSBURG PHILLIPS - TX
D
69
2.4
1
3
133
FRIEND RANCH - TX
T
138
69
13.2
63
1
134
FRIEND RANCH - TX
T
2.4
DRCS
1
10
135
FRIESS RANCH - TX
D
69
12.5
2
3
136
FT CHADBOURNE - TX
D
138
13.09
11
1
137
FT PHANTOM CLEAR FORK PUM - TX
D
69
2.4
13
3
138
FT PHANTOM EAST PUMP STA - TX
D
69
4.3
2
3
139
FT PHANTOM PLANT - TX
T
138
STATCAP
1
29
140
GILLESPIE (KNOX CITY REA - TX
D
69
12.47
3
3
141
GIRARD - TX
D
69
2.4
1
3
142
GRAYBACK - TX
D
69
13.09
5
3
143
GRIMES FILTRATION PLAN - TX
D
12
4.1
5
3
144
HAMLIN - TX
D
69
13
8
3
145
HAMLIN PLASTERCO CELOTEX THR - TX
D
69
13
2
3
146
HAMLIN REA - TX
D
69
12.4
2
2
147
HAMLIN REA - TX
D
69
12.47
1
1
148
HAMLIN SHELL PUMP - TX
D
12
2.4
1
3
149
HAMLIN SHELL PUMP - TX
D
69
7.2
1
3
150
HAMLIN TEXAS PIPE LINE - TX
D
69
12.4
11
3
151
HAMLIN TEXAS PIPE LINE - TX
D
69
13.09
1
1
152
HARROLD OIL FIELD - TX
D
69
13
4
1
153
HARTFORD STREET - TX
D
69
13
28
1
154
HASKELL - TX
D
69
7.56
10
3
155
HASKELL TEXAS PIPE LINE - TX
D
69
4.1
7
1
156
HATCHELL REA - TX
D
69
12.47
1
1
157
HATCHELL REA - TX
D
69
13
2
2
158
HAWLEY HUMBLE - EXXON - TX
D
12
2.4
1
3
159
HAWLEY HUMBLE - EXXON - TX
D
69
13.2
6
1
160
HORNET 69KV - TX
D
69
13.09
8
1
161
HUMBLE KEMPER EXXON - TX
D
69
2.4
5
6
162
INDIAN MESA - TX
D
138
13.09
5
3
163
IRAAN - TX
D
12
2.4
1
3
164
IRAAN - TX
D
69
13
10
3
165
IRAAN - TX
D
69
STATCAP
1
9
166
IRAAN AIR PRODUCTS - TX
D
69
2.4
15
3
167
IRAAN AIR PRODUCTS - TX
D
STATCAP
1
6
168
JAYTON - TX
T
69
4.1
2
3
169
JUNCTION - TX
D
69
13
3
1
170
JUNCTION - TX
D
69
13.09
5
2
171
KENNEDY PONDER TAP - TX
D
69
12.5
1
172
KIRKLAND - TX
D
69
2.4
1
3
173
KNOX CITY - TX
D
69
13
7
2
174
KNOX CITY - TX
D
69
13.09
3
1
175
LONGWORTH - TX
D
69
12.47
6
1
176
MAPLE STREET - TX
D
138
13.09
13.2
25
1
177
MARATHON YATES - TX
D
69
4
5
1
178
MARFA - TX
T
69
7.2
2
1
179
MARFA - TX
T
69
13
3
2
180
MARFA ALAMITO CREEK - TX
T
138
69
5.01
47
1
181
MARFA ALAMITO CREEK - TX
T
138
69
13.8
47
1
182
MARFA ALAMITO CREEK - TX
T
69
STATCAP
1
7
183
MASON PHILLIPS - TX
D
69
2.4
2
3
184
MASTERSON FIELD - TX
D
69
13
6
1
185
MATADOR - TX
T
69
13
5
3
186
MCCAMEY - TX
T
12
4.1
2
3
187
MCCAMEY - TX
T
138
12.47
9
1
188
MCCAMEY SHELL - TX
D
69
4.1
8
1
189
MCCAMEY SHELL PUMP - TX
D
12
2.4
1
1
190
MCCAMEY SHELL PUMP - TX
D
12
2.4
1
1
191
MCCAMEY SHELL PUMP - TX
D
12
4.16
1
3
192
MCELROY - TX
D
69
7.5
10
2
193
MCELROY - TX
D
69
7.56
5
1
194
MCELROY - TX
D
69
13.09
20
1
195
MCELROY - TX
D
12
STATCAP
1
2
196
MCELROY - TX
D
69
STATCAP
1
7
197
MCMURRY - TX
D
69
13
45
2
198
MELVIN - TX
D
69
13.09
9
1
199
MENARD PHILLIPS PETROLEUM CO. - TX
D
69
2.4
4
1
200
MERKEL - TX
D
69
13
9
1
201
MERKEL - TX
D
STATCAP
1
12
202
MERTZON - TX
D
69
13
5
1
203
MESA VIEW - TX
D
138
13.09
50
1
204
MIDWAY LANE - TX
D
69
12.5
10
3
205
MILES (WT) - TX
T
69
13
2
3
206
MORAN - TX
D
69
13.1
3
3
207
MULBERRY CREEK - TX
T
345
138
13.2
530
2
208
MULBERRY CREEK - TX
T
12
REACTIVE SPECIAL
1
209
MUNDAY - TX
D
69
13.09
9
1
210
MUNDAY EAST - TX
T
138
69
13.09
54
1
211
MUNDAY EAST - TX
T
138
STATCAP
1
29
212
NORTH BRADY - TX
T
69
10
2
213
NORTH BRADY - TX
T
69
2.2
10
2
214
NORTH MCCAMEY - TX
T
138
13.09
28
1
215
OKLAUNION HVDC INTER - TX
T
345
26.4
26.4
540
2
216
OKLAUNION HVDC INTER - TX
T
345
26.4
26.4
270
1
217
OKLAUNION HVDC INTER - TX
T
345
REACTIVE SPECIAL
8
218
OVER STREET - TX
D
69
13.09
4.16
25
1
219
OWLS - TX
D
138
69
13.09
90
1
220
OZONA - TX
D
69
13
13
1
221
PADUCAH - TX
D
69
12.5
4
3
222
PAINT CREEK PLANT - TX
T
138
70.5
36.2
90
1
223
PAINT ROCK - TX
D
69
4.1
334
3
224
PAISANO - TX
D
69
12.5
1
1
225
PAN AMERICAN - TX
D
69
2.4
1
226
PANDALE 69KV SUB - TX
D
69
13.09
12
1
227
PEACOCK (WT) - TX
D
69
2.4
1
3
228
PECAN BAYOU - TX
D
138
12.47
28
1
229
PECOS VALLEY - TX
D
69
12.5
1
3
230
PERKINS-PROTHO - TX
D
69
12.5
1
3
231
POWELL FIELD - TX
D
69
13.09
15
1
232
POWELL FIELD - TX
D
69
STATCAP
2
9
233
POWELL SHELL - TX
D
69
4
5
3
234
PUNCHER 69KV - TX
D
69
13.09
8
1
235
PUNCHER 69KV - TX
D
69
STATCAP
1
7
236
PUTNAM - TX
T
138
70.5
12.47
90
1
237
PUTNAM - TX
T
138
138
150
1
238
PUTNAM - TX
T
138
STATCAP
1
29
239
PUTNAM 69KV - TX
D
69
12.5
4
1
240
QUANAH - TX
D
69
12
15
3
241
QUANAH ACME MILLS - TX
D
12
2.4
2
3
242
RADIUM - TX
T
138
69
7.83
63
1
243
RAINEY CREEK - TX
D
138
13.09
13.8
28
1
244
RANKIN - TX
D
69
13.09
10
1
245
REBECCA LANE - TX
D
138
13.09
5.67
25
1
246
RIO PECOS PLANT (GIRVIN) - TX
T
138
69
13.8
63
1
247
RIO PECOS PLANT (GIRVIN) - TX
T
138
69.3
13.2
50
1
248
RIO PECOS PLANT (GIRVIN) - TX
T
69
12
4
1
249
RIO PECOS PLANT (GIRVIN) - TX
T
138
STATCAP
1
29
250
RIO PECOS PLANT (GIRVIN) - TX
T
138
AIR CORE REACTOR
7
140
251
RISING STAR - TX
D
69
13
4
1
252
ROARING SPRINGS - TX
D
69
12.47
6
1
253
ROBERT LEE - TX
D
69
13
11
1
254
ROBERTSON PRISON - TX
D
69
7.5
9
3
255
ROBY - TX
T
69
13
6
1
256
ROCHESTER - TX
D
69
12.47
5
1
257
ROTAN - TX
D
69
7.56
9
2
258
ROTAN - TX
D
69
13
3
1
259
ROTAN GYP MILL EAST - TX
D
12
0.48
3
6
260
ROUND TOP - TX
D
69
13
13
1
261
ROWENA - TX
D
69
13
5
1
262
RULE - TX
D
69
13.09
5
2
263
RULE - TX
D
69
13.09
2
1
264
RUSSEK STREET - TX
T
138
13.09
50
2
265
RUSTHILL - TX
T
138
70.5
13.09
78
1
266
S.A. AVENUE N. - TX
D
69
13
22
1
267
S.A. AVENUE N. - TX
D
12
STATCAP
1
2
268
S.A. BEN FICKLIN - TX
D
138
13.09
28
1
269
S.A. COKE ST - TX
D
138
13.09
28
1
270
S.A. COLLEGE HILLS WEST - TX
T
138
13.09
22
1
271
S.A. COLLEGE HILLS WEST - TX
T
138
69
13.53
63
1
272
S.A. COLLEGE HILLS WEST - TX
T
138
13.09
28
1
273
S.A. COLLEGE HILLS WEST - TX
T
69
STATCAP
1
22
274
S.A. CONCHO PLANT - TX
T
138
12.47
28
1
275
S.A. EMERSON ST. - TX
D
69
13
28
1
276
S.A. GRAPE CREEK - TX
D
69
13.09
10
3
277
S.A. HIGHLAND - TX
D
138
13.09
28
1
278
S.A. JACKSON ST. - TX
D
69
13
56
2
279
S.A. LAKE DRIVE - TX
D
138
13.09
28
1
280
S.A. MATHIS AIR FIELD - TX
D
69
4.36
9
1
281
S.A. NORTH - TX
T
69
13
28
1
282
S.A. NORTH - TX
T
138
69
6.57
63
1
283
S.A. NORTH - TX
T
STATCAP
2
24
284
S.A. PAULANN - TX
D
138
12.47
25
1
285
S.A. RED CREEK - TX
T
345
138
13.8
450
1
286
S.A. RED CREEK - TX
T
345
REACTOR
1
100
287
S.A. RED CREEK - TX
T
STATCAP
2
50
288
S.A. RED CREEK - TX
T
12
AIR CORE REACTOR
1
289
S.A. SOUTH - TX
D
138
13.09
28
1
290
S.A. SOUTH - TX
D
69
12.47
28
1
291
S.A. SOUTH - TX
D
STATCAP
1
2
292
S.A. SOUTHLAND HILLS - TX
D
138
13.09
28
1
293
S.A. WALNUT STREET - TX
D
69
13
25
1
294
SAGE - TX
D
69
12.5
25
1
295
SANTA ANNA - TX
T
138
69
14.4
34
1
296
SANTA ANNA - TX
T
69
13.09
6
1
297
SANTA RITA - TX
D
69
13.09
30
2
298
SARAGOSA - TX
D
69
13
8
1
299
SHAFTER MINE 4KV MINE - TX
D
69
12
23
3
300
SHEFFIELD (WT) - TX
D
69
12.47
2
1
301
SHEFFIELD (WT) - TX
D
69
13
5
3
302
SHELTON STREET - TX
D
69
13
50
2
303
SILVER - TX
D
69
12.47
25
1
304
SILVER - TX
D
69
STATCAP
1
7
305
SILVER - TX
D
STATCAP
1
306
SONORA - TX
T
69
13
10
3
307
SONORA - TX
T
138
69
13.2
42
1
308
SONORA - TX
T
138
STATCAP
2
58
309
SONORA ATLANTIC - TX
D
69
12
2
3
310
SONORA ATLANTIC - TX
D
69
13
4
1
311
SONORA CITY - TX
T
69
13
13
1
312
SONORA CITY - TX
T
69
STATCAP
1
12
313
SOUTH CROSS - TX
D
69
4.1
8
3
314
SOUTH CROSS - TX
D
69
STATCAP
1
4
315
SPUDDER FLAT - TX
D
138
12.47
9
1
316
SPUR - TX
D
69
2.52
2
2
317
SPUR - TX
D
69
4.1
1
1
318
SPUR - TX
D
69
7.56
2
3
319
SPUR - TX
D
138
69
5.1
56
1
320
SPUR - TX
D
69
STATCAP
1
12
321
STAMFORD - TX
D
69
13
28
1
322
STAMFORD PUMP - TX
D
69
12.5
1
1
323
STAMFORD PUMP - TX
D
69
13.09
1
1
324
STAMFORD PUMP - TX
D
69
13.1
1
1
325
STERLING CITY - TX
T
69
13
7
1
326
SUN VALLEY - TX
D
69
12.5
2
3
327
SWENSON - TX
D
69
12.5
1
3
328
TALPA ATLANTIC - TX
D
69
7.2
1
3
329
TALPA ATLANTIC - TX
D
69
13
502
4
330
TALPA ATLANTIC - TX
D
69
13.1
501
2
331
TANKERSLEY - TX
D
69
13
5
1
332
TEXAS-NEW MEXICO - TX
D
69
4
2
3
333
THROCKMORTON - TX
D
69
13
5
1
334
THROCKMORTON WOODSON OIL CO - TX
D
69
7.2
1
3
335
TRENT (WT) - TX
D
69
7.2
3
3
336
TRUSCOTT CITY - TX
D
69
7.2
1
2
337
TRUSCOTT CITY - TX
D
69
12.47
1
338
TRUSCOTT HUMBLE - TX
D
34.5
2.3
1
3
339
TURKEY - TX
D
69
13
4
1
340
TUSCOLA - TX
D
69
12.47
8
1
341
TUSCOLA - TX
D
69
13
9
1
342
TUSCOLA - TX
D
69
STATCAP
1
14
343
TWILIGHT TRAILS - TX
D
138
13.09
20
1
344
VALENTINE TAP - TX
D
69
7.2
2
3
345
VALENTINE TAP - TX
D
69
13
1
1
346
VALERA - TX
D
69
12.47
1
3
347
VERNON MAIN ST. SUB. - TX
T
69
13
27
4
348
VERNON MAIN ST. SUB. - TX
T
138
69
63
1
349
VERNON MAIN ST. SUB. - TX
T
138
STATCAP
2
29
350
VERNON PLANT SUB - TX
D
69
12.47
14
1
351
VOGEL STREET - TX
D
69
13
25
1
352
WAGGONER REFINERY - TX
D
69
7
1
1
353
WAGGONER REFINERY - TX
D
69
7.2
2
2
354
WAGGONER REFINERY - TX
D
69
12.47
1
1
355
WALNUT STREET - TX
D
69
13
20
1
356
WEINERT - TX
D
69
13.09
3
1
357
WEST TEXAS GULF - TX
D
69
4.36
6
3
358
WINTERS - TX
D
69
12.47
11
1
359
WYLIE CHAMPION - TX
D
138
13.09
5.9
25
1
360
AIRLINE(CP) - TX
T
138
69
12
448
2
361
AIRLINE(CP) - TX
T
69
12.47
106
4
362
AIRLINE(CP) - TX
T
138
STATCAP
1
58
363
AIRLINE(CP) - TX
T
69
STATCAP
3
26
364
AIRLINE(CP) - TX
T
69
AIR CORE REACTOR
5
365
ALAZAN - TX
D
138
24.9
11
1
366
ALAZAN - TX
D
26
12.47
9
1
367
ALICE - TX
T
69
12.47
37
2
368
ALICE - TX
T
138
69
12
93
1
369
ALICE - TX
T
12
STATCAP
2
5
370
AMISTAD - TX
D
138
12.47
6
1
371
ANNA STREET - TX
D
138
12.47
80
2
372
ANNA STREET - TX
D
12
STATCAP
3
2
373
ARANSAS PASS - TX
T
138
69
12
224
1
374
ARCADIA - TX
D
138
12.47
90
2
375
ARCADIA - TX
D
12
STATCAP
2
5
376
ARMSTRONG - TX
D
138
12.47
6
1
377
ASHERTON - TX
T
69
7.2
5
3
378
ASHERTON - TX
T
138
69
13.09
130
1
379
ASHERTON - TX
T
138
STATCAP
1
14
380
ASHERTON - TX
T
69
STATCAP
1
14
381
B&B GRAVEL - TX
D
69
12.47
5
3
382
BANQUETE - TX
D
69
12.47
9
1
383
BAY CITY - TX
D
138
12.47
90
2
384
BAY CITY - TX
D
138
STATCAP
1
14
385
BAY CITY PUMP NO. 1 - TX
D
69
2.3
1
3
386
BAY CITY PUMP NO. 3 - TX
D
69
2.3
3
3
387
BEEVILLE - TX
D
69
12.47
28
1
388
BEEVILLE - TX
D
69
2.2
10
1
389
BEEVILLE - TX
D
12
STATCAP
1
5
390
BEEVILLE - TX
D
69
STATCAP
3
46
391
BERCLAIR - TX
D
69
7.5
3
3
392
BIG FOOT SW - TX
T
138
69
12.47
37
1
393
BIG FOOT SW - TX
T
138
STATCAP
1
14
394
BIG FOOT SW - TX
T
69
STATCAP
1
7
395
BIG OAK - TX
D
23
12
1
1
396
BIG OAK - TX
D
69
13.09
25
1
397
BIG WELLS - TX
D
138
12.47
11
1
398
BISHOP - TX
D
69
12.47
9
1
399
BLACK BAYOU - TX
D
138
12.47
11
1
400
BLESSING - TX
T
69
12
6
4
401
BLESSING - TX
T
138
69
12.47
83
1
402
BLESSING - TX
T
345
138
12.47
600
1
403
BRACKETTVILLE - TX
D
138
12.47
6
1
404
BROOKHOLLOW - TX
D
69
12.47
36
2
405
BROOKHOLLOW - TX
D
12
STATCAP
1
2
406
BROWNSVILLE (CP) - TX
D
69
12.47
20
2
407
BROWNSVILLE (CP) - TX
D
12
STATCAP
2
5
408
BRUNI - TX
D
138
13.09
13
1
409
BUENA VISTA - TX
D
138
12.47
28
1
410
CAMPWOOD - TX
D
26
12.47
3
1
411
CAMPWOOD - TX
D
26
12.47
7.2
3
1
412
CAMPWOOD - TX
D
69
7.2
5
3
413
CAMPWOOD - TX
D
69
STATCAP
2
7
414
CARBIDE - TX
T
138
69
12.47
280
2
415
CASA BLANCA - TX
D
69
13.09
9
1
416
CASA BLANCA - TX
D
12
STATCAP
1
2
417
CATARINA - TX
T
138
12
25
1
418
CAUSEWAY - TX
D
138
12.47
28
1
419
CAUSEWAY - TX
D
12
STATCAP
2
7
420
CHARLOTTE - TX
D
69
13.09
9
1
421
CHARLOTTE - TX
D
12
STATCAP
1
2
422
CHASE FIELD - TX
D
69
12.47
9
1
423
CHOCOLATE BAYOU - TX
T
138
13.09
9
1
424
CHOKE CANYON - TX
D
138
13.09
15
1
425
CITRUS CITY - TX
T
138
13.09
50
2
426
CLARKWOOD - TX
D
138
12.47
56
2
427
CLARKWOOD - TX
D
12
STATCAP
1
2
428
CLEMVILLE - TX
D
69
12.47
9
1
429
COFFEE PORT - TX
D
138
12.47
11
1
430
COFFEE PORT - TX
D
138
STATCAP
1
29
431
COLETO CREEK - TX
T
345
138
12.47
600
1
432
COLETO CREEK - TX
T
345
138
13.8
600
1
433
COLETO CREEK - TX
T
13.8
AIR CORE REACTOR
12
127
434
COLUMBUS - TX
D
69
12.47
9
1
435
COMSTOCK - TX
D
138
13
8
1
436
CONOCO - TX
D
138
12.47
6
1
437
CONTINENTAL(CP) - TX
D
69
7.2
5
3
438
COTULLA - TX
D
138
12
50
2
439
COTULLA - TX
D
12
STATCAP
1
2
440
CRESTONIO - TX
D
138
12.47
19
2
441
DARST - TX
D
69
12.47
20
2
442
DARST - TX
D
12
STATCAP
2
1
443
DEL MAR - TX
D
138
12.47
28
1
444
DEL MAR - TX
D
138
STATCAP
3
75
445
DEL RIO - TX
D
138
12.47
53
2
446
DEL RIO - TX
D
12
STATCAP
4
19
447
DEVINE - TX
D
69
12.47
19
3
448
DEVINE - TX
D
12
STATCAP
3
7
449
DILLEY - TX
D
69
13.09
19
2
450
DILLEY SW - TX
T
138
69
12.47
37
1
451
DILLEY SW - TX
T
138
STATCAP
2
113
452
DILLEY SW - TX
T
69
STATCAP
3
26
453
DILLEY SW - TX
T
69
AIR CORE REACTOR
6
454
DIMMIT - TX
D
138
13.09
25
1
455
EAGLE LAKE - TX
D
69
12.47
20
2
456
EAGLE LAKE - TX
D
12
STATCAP
2
5
457
EAGLE PASS - TX
D
138
12.47
28
1
458
EAGLE PASS - TX
D
138
13.09
25
1
459
EAGLE PASS - TX
D
12
STATCAP
4
14
460
EAGLE PASS - TX
D
138
STATCAP
2
31
461
EAGLE PASS HVDC - TX
T
138
17.9
95
2
462
EAGLE PASS HVDC - TX
T
18
STATCAP
4
25
463
EAGLE PASS HVDC - TX
T
13.2
REACTIVE SPECIAL
1
464
EAST HARRISON - TX
D
69
12.47
101
3
465
EAST HARRISON - TX
D
12
STATCAP
5
24
466
EDNA - TX
D
138
12.47
19
2
467
EDROY - TX
D
69
AIR CORE REACTOR
3
468
EL CAMPO - TX
T
138
12.47
28
1
469
EL CAMPO - TX
T
69
12.47
28
1
470
EL CAMPO - TX
T
138
69
12.47
93
1
471
EL CAMPO - TX
T
12
STATCAP
2
5
472
EL GATO - TX
D
138
13.09
40
1
473
ELSA - TX
D
138
12.47
56
2
474
ELSA - TX
D
12
STATCAP
2
5
475
ENCINAL - TX
D
138
12.47
5
1
476
ESCONDIDO - TX
T
138
12.47
25
1
477
ESCONDIDO - TX
T
138
STATCAP
1
14
478
FALCON SW - TX
T
138
STATCAP
1
14
479
FALFURRIAS - TX
T
138
12.47
11
1
480
FALFURRIAS - TX
T
69
12.47
9
1
481
FALFURRIAS - TX
T
138
69
13.09
54
1
482
FOSTER FIELD - TX
D
69
12.47
9
1
483
FREER - TX
D
69
12.47
9
1
484
FREER - TX
D
69
13.09
9
1
485
FREER - TX
D
12
STATCAP
4
10
486
FRONTERA SWITCH - TX
T
138
STATCAP
2
115
487
FULTON (CP) - TX
D
69
12.47
28
1
488
GANADO - TX
D
138
12.47
9
1
489
GARCENO - TX
D
138
12.47
25
1
490
GARWOOD CITY - TX
D
69
12.47
5
3
491
GARWOOD IDEAL - TX
D
69
4.16
3
3
492
GARWOOD PUMP - TX
D
69
2.3
2
3
493
GARWOOD RELIFT - TX
D
69
2.3
90
3
494
GARZA - TX
T
138
69
12.5
83
1
495
GARZA - TX
T
69
STATCAP
1
11
496
GATEWAY (CP) - TX
D
138
12.47
68
2
497
GEORGE WEST - TX
D
138
12.47
9
1
498
GEORGE WEST - TX
D
12
STATCAP
2
5
499
GOHLKE - TX
D
138
12.47
6
1
500
GOLIAD - TX
D
69
12.47
9
1
501
GOODWIN - TX
D
138
12.47
25
1
502
GOODWIN - TX
D
138
13.09
25
1
503
GOVERNMENT WELLS - TX
D
26
12.47
3
1
504
GOVERNMENT WELLS - TX
D
69
12.47
11
1
505
GOVERNMENT WELLS - TX
D
69
24.9
11
1
506
GOVERNMENT WELLS - TX
D
12
STATCAP
2
5
507
GOVERNMENT WELLS - TX
D
24.94
STATCAP
2
5
508
GREENLAKE - TX
D
69
7.2
3
2
509
GREENLAKE - TX
D
69
12.47
7
4
510
GREGORY - TX
D
69
13.09
50
2
511
GRETA - TX
D
69
12.47
11
1
512
HAINE DRIVE - TX
D
138
12.47
56
2
513
HAINE DRIVE - TX
D
12
STATCAP
1
5
514
HALL ACRES ROAD - TX
D
138
12.47
92
2
515
HARLINGEN NO. 1 - TX
D
69
12.47
56
2
516
HARLINGEN NO. 1 - TX
D
12
STATCAP
2
10
517
HARLINGEN SW ST - TX
T
69
13.09
50
2
518
HARLINGEN SW ST - TX
T
138
69
13.09
130
1
519
HARLINGEN SW ST - TX
T
12
STATCAP
2
10
520
HEARD - TX
D
69
2.4
5
3
521
HEARN ROAD - TX
D
69
7.2
19
3
522
HEARN ROAD - TX
D
69
12.47
28
1
523
HIDALGO - TX
D
138
12.47
25
2
524
HIGHWAY 9 - TX
T
69
12.47
101
3
525
HIGHWAY 9 - TX
T
138
70.5
12.47
200
1
526
HOCHHEIM - TX
D
69
2.4
2
3
527
HOLLY - TX
D
138
12.47
90
2
528
HOMEPORT - TX
D
138
12.47
28
1
529
INDUSTRIAL - TX
D
69
12.47
56
2
530
INGLESIDE CITY - TX
D
138
12.47
56
2
531
JOURDANTON - TX
D
12
STATCAP
2
5
532
JOURDANTON - TX
D
69
STATCAP
2
43
533
KARNES CITY - TX
D
138
13.09
25
1
534
KENEDY - TX
D
69
12.47
11
1
535
KENEDY SWITCH - TX
T
138
12.47
11
1
536
KENEDY SWITCH - TX
T
69
12.47
9
1
537
KENEDY SWITCH - TX
T
138
69
12.47
93
1
538
KINGSVILLE - TX
D
138
12.47
56
2
539
KLEBERG - TX
D
138
12.47
56
2
540
KLEBERG - TX
D
138
STATCAP
1
29
541
KNIPPA - TX
D
69
7.2
5
3
542
KOCH UP RIVER - TX
T
138
69
12.47
93
1
543
LA PALMA 138KV - TX
T
138
STATCAP
2
100
544
LA PALMA 138KV - TX
T
138
AIR CORE REACTOR
3
545
LA PALMA 345KV - TX
T
345
138
13.8
672
1
546
LA PALMA 345KV - TX
T
345
138
34.5
1
547
LA PALMA 69KV - TX
T
138
69
12
297
2
548
LAGUNA - TX
D
69
12.47
28
1
549
LAKESIDE (CP) - TX
D
69
2.3
5
3
550
LANE CITY - TX
T
138
STATCAP
1
29
551
LANE CITY PUMP - TX
D
138
4.16
5
1
552
LAREDO HEIGHTS - TX
D
138
12.47
80
2
553
LAREDO HEIGHTS - TX
D
12
STATCAP
4
14
554
LAREDO PLANT - TX
T
138
12.47
28
1
555
LAREDO PLANT - TX
T
12
STATCAP
4
19
556
LAREDO PLANT - TX
T
REACTIVE SPECIAL
1
557
LAREDO STATCOM - TX
T
34.5
14.04
227
6
558
LEARY LANE - TX
D
69
12.47
90
2
559
LIVE OAK - TX
D
69
12.47
28
1
560
LOLITA - TX
T
138
12.47
11
1
561
LON HILL - TX
T
138
69
12.47
200
1
562
LON HILL - TX
T
138
70.5
12.47
200
1
563
LON HILL - TX
T
345
138
13.8
960
2
564
LON HILL - TX
T
13.8
AIR CORE REACTOR
1
565
LON HILL - TX
T
7.62
AIR CORE REACTOR
2
28
566
LON HILL - TX
T
138
STATCAP
2
567
LONE STAR - TX
D
69
12.47
2
3
568
LONE TREE - TX
D
69
12.47
1
1
569
LONE TREE - TX
D
69
STATCAP
1
14
570
LOS FRESNOS - TX
D
138
12.47
50
2
571
LYTLE - TX
D
69
7.2
5
3
572
MAGILL 138KV - TX
D
138
STATCAP
1
29
573
MAGNOLIA - TX
D
138
13.09
13
1
574
MAGRUDER - TX
D
69
12.47
56
2
575
MALONE - TX
D
69
12.47
5
3
576
MALONE - TX
D
12
STATCAP
1
2
577
MARKHAM - TX
D
69
12.47
6
1
578
MATHIS - TX
D
69
12.47
20
2
579
MATHIS - TX
D
12
STATCAP
2
2
580
MATTHEWS - TX
D
69
12.47
5
3
581
MAVERICK - TX
D
138
12.47
5
1
582
MAYBERRY - TX
T
138
13.09
24
1
583
MAYBERRY - TX
T
138
13.09
40
1
584
MAYO - TX
D
138
13.09
25
1
585
MCCOLL ROAD - TX
D
138
12.47
40
1
586
MCKENZIE ROAD - TX
D
138
12.47
28
1
587
MEDIO CREEK - TX
D
138
12.47
11
1
588
MILITARY HIGHWAY - TX
T
138
13.09
13
1
589
MILITARY HIGHWAY - TX
T
34.5
14.04
151
4
590
MILITARY HIGHWAY - TX
T
138
STATCAP
2
115
591
MILO - TX
D
138
12.47
28
1
592
MINES ROAD - TX
D
138
12.47
28
1
593
MINES ROAD - TX
D
12
STATCAP
2
5
594
MOCKINGBIRD - TX
D
138
13.09
25
1
595
MOORE FIELD - TX
D
138
12.47
25
2
596
MOORE FIELD - TX
D
23
12.47
2.4
11
1
597
MOORE FIELD - TX
D
26
12.47
11
1
598
MORRIS STREET - TX
D
138
12.47
179
4
599
MUSTANG ISLAND - TX
D
69
13.09
9
1
600
NAVAL BASE - TX
D
138
70.5
13.09
120
1
601
NELSON SHARPE III - TX
T
138
138
150
1
602
NELSON SHARPE III - TX
T
345
138
13.8
675
1
603
NELSON SHARPE III - TX
T
138
STATCAP
2
86
604
NORDHEIM - TX
D
138
13.09
13
1
605
NORMANNA CST - TX
D
69
12.47
2
3
606
NORTH ALAMO - TX
D
138
12.47
22
1
607
NORTH ALAMO - TX
D
138
13.09
25
1
608
NORTH ALAMO - TX
D
12
STATCAP
2
5
609
NORTH EDINBURG 345 - TX
T
69
12.47
28
1
610
NORTH EDINBURG 345 - TX
T
69
13.09
25
1
611
NORTH EDINBURG 345 - TX
T
13.2
REACTOR
1
15
612
NORTH EDINBURG 345 - TX
T
138
69
12
83
1
613
NORTH EDINBURG 345 - TX
T
138
69
13.2
73
1
614
NORTH EDINBURG 345 - TX
T
345
138
12
1200
2
615
NORTH EDINBURG 345 - TX
T
138
STATCAP
1
50
616
NORTH EDINBURG 345 - TX
T
345
STATCAP
1
933
617
NORTH EDINBURG 345 - TX
T
12
AIR CORE REACTOR
2
14
618
NORTH ELLA - TX
D
69
2.3
3
3
619
NORTH MCALLEN - TX
D
138
12.47
125
3
620
NORTH MCALLEN - TX
D
12
STATCAP
3
12
621
NORTH MERCEDES - TX
D
138
13.09
50
2
622
NORTH MERCEDES - TX
D
12
STATCAP
1
2
623
NORTH PADRE ISLE. 69 - TX
D
69
12.47
28
1
624
NORTH PADRE ISLE. 69 - TX
D
69
13
28
1
625
NORTH PADRE ISLE. 69 - TX
D
138
STATCAP
1
14
626
NORTH VICTORIA - TX
D
69
12.47
90
2
627
NORTH VICTORIA - TX
D
12
STATCAP
1
2
628
NORTH WESLACO - TX
D
138
12.47
13
1
629
NORTH WESLACO - TX
D
12
STATCAP
1
2
630
OCONNER - TX
D
69
12.47
3
1
631
ODEM - TX
D
69
7.2
5
3
632
ODEM - TX
D
69
12.47
11
1
633
OLEANDER - TX
T
138
70.5
12.47
130
1
634
OLMITO - TX
D
138
12.47
25
1
635
PALACIOS - TX
D
69
12.47
11
1
636
PALMHURST - TX
D
138
12.47
87
2
637
PALMHURST - TX
D
12
STATCAP
2
7
638
PALMVIEW - TX
D
138
12.47
68
2
639
PARKER - TX
D
69
12.47
5
3
640
PEARSALL - TX
D
69
12.47
19
2
641
PEARSALL - TX
D
12
STATCAP
2
5
642
PETTUS - TX
D
69
13.09
13
1
643
PETTUS - TX
D
69
24.9
11
1
644
PHARAOH - TX
D
138
12.47
56
2
645
PHARR - TX
T
138
12.47
75
2
646
PICACHO - TX
D
138
STATCAP
1
29
647
PLACEDO - TX
D
69
12.47
6
1
648
PLEASANTON - TX
T
138
12.47
56
2
649
PLEASANTON - TX
T
138
70.5
13.09
54
1
650
POINT COMFORT - TX
D
69
12
2
1
651
POINT COMFORT - TX
D
69
12.47
3
2
652
POLK AVENUE - TX
D
138
12.47
92
2
653
POLK AVENUE - TX
D
12
STATCAP
6
24
654
PORT ARANSAS - TX
D
69
12.47
56
2
655
PORT ISABEL SWITCH - TX
T
138
12.47
9
1
656
PORT ISABEL SWITCH - TX
T
138
13.09
25
1
657
PORT ISABEL SWITCH - TX
T
12
STATCAP
2
5
658
PORT LAVACA - TX
D
69
12.47
9
1
659
PORT LAVACA - TX
D
69
13.09
9
1
660
PORT LAVACA - TX
D
12
STATCAP
1
2
661
PORT LAVACA - TX
D
69
STATCAP
1
7
662
PORT LAVACA - TX
D
AIR CORE REACTOR
1
663
PORTLAND (CP) - TX
D
138
12.47
56
2
664
PORTLAND (CP) - TX
D
12
STATCAP
2
5
665
PRAIRIE PUMP - TX
D
69
12.47
5
3
666
PREMONT - TX
D
69
12.47
21
2
667
PREMONT - TX
D
13.2
REACTIVE SPECIAL
1
668
PUEBLO - TX
D
138
12.47
30
1
669
RACHAL - TX
D
138
12.47
13
1
670
RANDADO - TX
D
138
12.47
5
1
671
RANGERVILLE - TX
D
23
12.47
8
1
672
RANGERVILLE - TX
D
69
12.47
8
1
673
RANGERVILLE - TX
D
69
13.09
9
1
674
RANGERVILLE - TX
D
69
STATCAP
1
7
675
RAYMONDVILLE #1 - TX
D
69
12.47
36
2
676
RAYMONDVILLE #1 - TX
D
12
STATCAP
2
5
677
RAYMONDVILLE #2 - TX
T
26
12.47
11
1
678
RAYMONDVILLE #2 - TX
T
69
12.47
11
1
679
RAYMONDVILLE #2 - TX
T
138
70.5
12.47
54
1
680
RAYMONDVILLE #2 - TX
T
12
STATCAP
2
5
681
RAYMONDVILLE #2 - TX
T
138
STATCAP
1
15
682
REFUGIO - TX
D
69
12.47
21
2
683
REFUGIO - TX
D
12
STATCAP
4
10
684
RINCON - TX
T
138
69
13.8
84
1
685
RIO BRAVO - TX
D
138
24.9
11
1
686
RIO BRAVO - TX
D
138
24.94
13
1
687
RIO BRAVO - TX
D
26
12.47
14
2
688
RIO BRAVO - TX
D
26
12.47
7
1
689
RIO GRANDE CITY - TX
D
69
12.47
28
1
690
RIO GRANDE CITY - TX
D
138
70.5
12.47
90
1
691
RIO GRANDE CITY - TX
D
12
STATCAP
4
10
692
RIO GRANDE CITY - TX
D
138
STATCAP
1
29
693
RIO HONDO SW STA - TX
T
345
138
13
600
1
694
RIO HONDO SW STA - TX
T
345
138
13.8
675
1
695
RIO HONDO SW STA - TX
T
138
STATCAP
2
105
696
RIO RICO - TX
D
69
12.47
18
2
697
RIO RICO - TX
D
12
STATCAP
1
2
698
RIO RICO - TX
D
69
STATCAP
1
11
699
RIVERSIDE (CP) - TX
D
69
2.3
5
3
700
ROCKPORT (CP) - TX
T
69
12.47
11
1
701
ROCKPORT (CP) - TX
T
138
69
13.09
108
2
702
ROCKSPRINGS ATL - TX
D
69
12.47
3
3
703
RODD FIELD - TX
D
138
12.47
92
2
704
ROMA - TX
T
138
12.47
25
2
705
ROMA - TX
T
12
STATCAP
1
2
706
RUNGE - TX
D
138
13.09
13
1
707
SABINAL - TX
D
69
7.2
5
3
708
SAN BENITO - TX
D
13.09
25
1
709
SAN BENITO - TX
D
69
12.47
25
1
710
SAN BENITO - TX
D
12
STATCAP
3
12
711
SAN DIEGO - TX
D
69
12.47
9
1
712
SAN DIEGO - TX
D
69
13.09
13
1
713
SAN DIEGO - TX
D
12
STATCAP
2
5
714
SAN YGNACIO - TX
D
138
12.47
6
1
715
SANTO NINO - TX
D
138
12.47
58
2
716
SANTO NINO - TX
D
12
STATCAP
2
7
717
SEAWALL - TX
D
69
12.47
9
1
718
SEAWALL - TX
D
69
13.09
13
1
719
SHARYLAND - TX
D
138
12.47
37
1
720
SHARYLAND - TX
D
138
12.47
50
1
721
SIERRA VISTA - TX
D
138
13.09
25
1
722
SINTON - TX
D
69
12.47
20
2
723
SKIDMORE - TX
D
69
13.09
6
1
724
SMITH - TX
D
69
2.3
5
3
725
SOUTH MCALLEN - TX
T
138
12.47
50
2
726
SOUTH MCALLEN - TX
T
12
STATCAP
2
5
727
SOUTH MCALLEN - TX
T
138
STATCAP
1
50
728
SOUTH MISSION - TX
D
138
12.47
50
2
729
SOUTH PADRE ISLAND - TX
D
138
12.47
56
2
730
SOUTH SANTA ROSA - TX
D
138
12.47
50
2
731
SOUTH SANTA ROSA - TX
D
138
STATCAP
1
29
732
SOUTHEAST EDINBURG - TX
D
138
12.47
56
2
733
SOUTHEAST EDINBURG - TX
D
12
STATCAP
1
2
734
SOUTHSIDE - TX
D
138
12.47
112
4
735
STADIUM - TX
D
69
12.47
56
2
736
STADIUM - TX
D
12
STATCAP
2
5
737
STAFFORD HILL - TX
D
69
12.47
3
3
738
STEVENS - TX
D
69
4.16
21
2
739
STEWART ROAD - TX
T
138
69
12
33
1
740
STEWART ROAD - TX
T
138
STATCAP
2
58
741
STRATTON (CP) - TX
T
138
69
12
1
742
SUNCHASE - TX
D
138
12.47
28
1
743
TAFT - TX
D
69
7.2
5
3
744
TAFT - TX
D
69
12.47
11
1
745
TATTON - TX
D
69
13.09
9
1
746
THOMASTON - TX
D
138
12.47
7
1
747
THREE RIVERS (COR) - TX
T
69
12.47
19
2
748
THREE RIVERS (COR) - TX
T
138
70.5
13.09
78
1
749
THREE RIVERS (COR) - TX
T
12
STATCAP
3
7
750
THREE RIVERS (COR) - TX
T
138
STATCAP
2
751
TYNAN - TX
D
69
13.09
1
752
UNIVERSITY - TX
D
138
12.47
28
1
753
UNIVERSITY - TX
D
138
13.09
25
1
754
UVALDE - TX
T
138
12.47
56
2
755
UVALDE - TX
T
138
69
13.09
54
1
756
UVALDE - TX
T
12
STATCAP
5
16
757
UVALDE - TX
T
138
STATCAP
1
14
758
UVALDE - TX
T
69
STATCAP
1
14
759
VICTORIA PLANT - TX
T
138
69
12.47
374
2
760
VICTORIA PLANT - TX
T
69
12
9
1
761
VICTORIA PLANT - TX
T
69
12.47
48
3
762
VICTORIA PLANT - TX
T
69
STATCAP
1
29
763
VILLA CAVAZOS - TX
D
138
12.47
25
1
764
WADSWORTH - TX
D
138
12.47
11
1
765
WASHINGTON STREET - TX
D
69
12.47
101
3
766
WATERWORKS (CP) - TX
D
69
0.46
2
3
767
WATERWORKS (CP) - TX
D
69
2.3
3
3
768
WEAVER ROAD - TX
D
69
12.47
9
1
769
WEIL TRACT - TX
D
138
12.47
45
1
770
WEIL TRACT - TX
D
138
STATCAP
2
58
771
WESLACO SWITCH - TX
T
138
STATCAP
2
86


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

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
A. Ray King Transmission Training Facility
(a)
OPCo
269,653
3
Administrative and General Expenses - Maintenance
AEPSC
3,398,837
4
Administrative and General Expenses - Operation
AEPSC
4,988,897
5
Audit Services
AEPSC
1,184,660
6
Civil & Political Activities & Other Services
AEPSC
681,392
7
Construction Services
AEPSC
105,333,177
8
Corporate Accounting
AEPSC
4,651,498
9
Corporate Communications
AEPSC
750,498
10
Coporate Planning & Budgeting
AEPSC
982,161
11
Coporate Safety & Health
AEPSC
580,004
12
Customer Accounts Expenses
AEPSC
5,316,649
13
Customer Service and Informational Expenses
AEPSC
415,405
14
Distribution Expenses - Operation
AEPSC
6,589,100
15
Fuel & Storeroom Services
AEPSC
4,453,458
16
Human Resources
AEPSC
2,138,272
17
HVDC East Tie
SWEPCo
749,282
18
Information Technology
AEPSC
8,255,327
19
Legal GC/Administration
AEPSC
3,971,637
20
Materials and Supplies
OPCo
739,714
21
Materials and Supplies
PSO
606,988
22
Materials and Supplies
SWEPCo
427,647
23
Non-fuel Oklaunion O&M Billings
PSO
2,028,230
24
Oklaunion Joint Books Allocation
PSO
14,355,607
25
Other Operating Revenues
ETT
1,538,093
26
Real Estate & Workplace Services
AEPSC
2,359,539
27
Regulatory Services
AEPSC
2,120,311
28
Research & Other Services
AEPSC
714,087
29
Sales Expenses
AEPSC
316,287
30
Strategy & Innovation
AEPSC
1,069,102
31
Transmission Expenses - Maintenance
AEPSC
1,820,395
32
Transmission Expenses - Operation
AEPSC
20,048,915
33
Treasury & Risk
AEPSC
1,154,669
19
20
Non-power Goods or Services Provided for Affiliated
21
Building and Property Leases
AEPSC
1,540,518
22
Construction Services
ETT
2,685,268
23
Construction Services
SWEPCo
1,064,343
24
Fleet and Vehicle Charges
AEPSC
261,097
25
HVDC North Transmission Tie
PSO
665,218
26
Material and Supplies
ETT
346,181
27
Material and Supplies
OPCo
856,188
28
Material and Supplies
PSO
1,170,179
29
Material and Supplies
SWEPCo
1,763,268
30
Transmission Expenses - Maintenance
ETT
1,330,857
31
Transmission Expenses - Operation
ETT
3,171,910
42


Name of Respondent:

AEP Texas Inc.
This report is:

(1)
An Original

(2)
A Resubmission
Date of Report:

Year/Period of Report

End of:
2018
/
Q4
FOOTNOTE DATA

(a) Concept: NameOfAssociatedAffiliatedCompany

 

Affiliated Companies shown in Column ( B ):

AEPSC - American Electric Power Service Corporation

ETT - Electric Transmission TX, LLC

OPCo - Ohio Power Company

PSO - Public Service Company of Oklahoma

SWEPCo - Southwestern Electric Power Company

 

AEPSC Allocations

 

Certain managerial and professional services provided by AEPSC are allocated among

multiple affiliates. The costs of the services are billed on a direct-charge basis, whenever

possible. Costs incurred to perform services that benefit more than one company are

allocated to the benefiting companies using one of 80 FERC accepted allocation factors.

The allocation factors used to bill for services performed by AEPSC are based upon

formulae that consider factors such as number of customers, number of employees,

number of transmission pole miles, number of invoices and other factors. The data upon

which these formulae are based is updated monthly, quarterly, semi-annually or annually,

depending on the particular factor and its volatility. The billings for services are made

at cost and include no compensation for a return on investment.

 

FLEET Allocations (Various)

 

Costs related to AEP's fleet vehicles are allocated in the same manner as the labor of each

department utilizing the vehicles. To the extent a department provides service to another

affiliate company, an applicable share of their fleet costs are also assigned to that

affiliate company.

 

(b) Concept: AccountsChargedOrCreditedTransactionsWithAssociatedAffiliatedCompanies

 

Various Account Listings

 

As Provided in Column (c)

FERC Accounts:

Various (1)

920,921,923,924,925,926,928,930.1,930.2,931

Various (2)

426.1,426.3,426.4

Various (3)

901,902,903,905

Various (4)

907,908,909,910

Various (5)

580,582,583,584,586,588,589

Various (6)

186,561.3,562,570,922,924,925

Various (7)

107,108,154,560,570,935

Various (8)

107,108,154,186,560,592,593,930

Various (9)

107,108,154,570,935

Various (10)

154,426.1,501,506,556,925,926

Various (11)

107,108,152,500,502,505,506,510,511,512,513,514,924

Various (12)

568,569,569.1,569.2,569.3,570,571,572,573

Various (13)

560,561.2,561.3,561.4,561.5,561.6,562,563,566,920,923

Various (14)

560,562,566,570,922,925,926

Various (15)

568'569'570'571'573

Various (16)

560,561.2,562,563,566

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