Document_and_Entity_Informatio
Document and Entity Information | 9 Months Ended | |
Sep. 30, 2013 | Oct. 24, 2013 | |
Entity Registrant Name | AMERICAN ELECTRIC POWER CO INC | |
Entity Central Index Key | 4904 | |
Document Type | 10-Q | |
Document Period End Date | 30-Sep-13 | |
Amendment Flag | FALSE | |
Document Fiscal Year Focus | 2013 | |
Document Fiscal Period Focus | Q3 | |
Current Fiscal Year End Date | -19 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 487,290,382 | |
Appalachian Power Co [Member] | ||
Entity Registrant Name | APPALACHIAN POWER CO | |
Entity Central Index Key | 6879 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 13,499,500 | |
Indiana Michigan Power Co [Member] | ||
Entity Registrant Name | INDIANA MICHIGAN POWER CO | |
Entity Central Index Key | 50172 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 1,400,000 | |
Ohio Power Co [Member] | ||
Entity Registrant Name | OHIO POWER CO | |
Entity Central Index Key | 73986 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 27,952,473 | |
Public Service Co Of Oklahoma [Member] | ||
Entity Registrant Name | PUBLIC SERVICE CO OF OKLAHOMA | |
Entity Central Index Key | 81027 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 9,013,000 | |
Southwestern Electric Power Co [Member] | ||
Entity Registrant Name | SOUTHWESTERN ELECTRIC POWER CO | |
Entity Central Index Key | 92487 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 7,536,640 |
Consolidated_Statements_of_Inc
Consolidated Statements of Income (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Revenues | ||||
Utility Operations | $3,797,000,000 | $3,814,000,000 | $10,539,000,000 | $10,412,000,000 |
Other Revenues | 379,000,000 | 342,000,000 | 1,045,000,000 | 920,000,000 |
TOTAL REVENUES | 4,176,000,000 | 4,156,000,000 | 11,584,000,000 | 11,332,000,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 1,168,000,000 | 1,180,000,000 | 3,107,000,000 | 3,137,000,000 |
Purchased Electricity for Resale | 373,000,000 | 327,000,000 | 1,103,000,000 | 855,000,000 |
Other Operation | 677,000,000 | 775,000,000 | 2,079,000,000 | 2,150,000,000 |
Maintenance | 261,000,000 | 255,000,000 | 839,000,000 | 769,000,000 |
Asset Impairments and Other Related Charges | 144,000,000 | 13,000,000 | 298,000,000 | 13,000,000 |
Depreciation and Amortization | 447,000,000 | 470,000,000 | 1,310,000,000 | 1,353,000,000 |
Taxes Other Than Income Taxes | 231,000,000 | 224,000,000 | 671,000,000 | 648,000,000 |
TOTAL EXPENSES | 3,301,000,000 | 3,244,000,000 | 9,407,000,000 | 8,925,000,000 |
OPERATING INCOME (LOSS) | 875,000,000 | 912,000,000 | 2,177,000,000 | 2,407,000,000 |
Other Income (Expense): | ||||
Interest and Investment Income | 3,000,000 | 2,000,000 | 55,000,000 | 6,000,000 |
Carrying Costs Income | 8,000,000 | 11,000,000 | 20,000,000 | 42,000,000 |
Allowance for Equity Funds Used During Construction | 19,000,000 | 23,000,000 | 51,000,000 | 70,000,000 |
Interest Expense | -225,000,000 | -233,000,000 | -685,000,000 | -697,000,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 680,000,000 | 715,000,000 | 1,618,000,000 | 1,828,000,000 |
Income Tax Expense (Credit) | 257,000,000 | 241,000,000 | 520,000,000 | 620,000,000 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 11,000,000 | 14,000,000 | 39,000,000 | 33,000,000 |
NET INCOME (LOSS) | 434,000,000 | 488,000,000 | 1,137,000,000 | 1,241,000,000 |
Net Income Attributable to Noncontrolling Interests | 1,000,000 | 1,000,000 | 3,000,000 | 3,000,000 |
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS | 433,000,000 | 487,000,000 | 1,134,000,000 | 1,238,000,000 |
Earnings Per Share | ||||
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | 486,932,747 | 484,979,543 | 486,353,876 | 484,437,875 |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $0.89 | $1 | $2.33 | $2.55 |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | 487,258,905 | 485,362,858 | 486,792,914 | 484,826,123 |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $0.89 | $1 | $2.33 | $2.55 |
CASH DIVIDENDS DECLARED PER SHARE | $0.49 | $0.47 | $1.45 | $1.41 |
Appalachian Power Co [Member] | ||||
Revenues | ||||
Utility Operations | 756,606,000 | 776,066,000 | 2,299,587,000 | 2,161,901,000 |
Sales to AEP Affiliates | 90,558,000 | 84,940,000 | 241,311,000 | 216,284,000 |
Other Revenues | 2,569,000 | 3,192,000 | 6,833,000 | 7,950,000 |
TOTAL REVENUES | 849,733,000 | 864,198,000 | 2,547,731,000 | 2,386,135,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 207,442,000 | 241,448,000 | 575,902,000 | 609,985,000 |
Purchased Electricity for Resale | 47,391,000 | 45,196,000 | 172,334,000 | 155,421,000 |
Purchased Electricity from AEP Affiliates | 220,736,000 | 181,134,000 | 625,534,000 | 463,015,000 |
Other Operation | 64,508,000 | 92,700,000 | 223,180,000 | 239,704,000 |
Maintenance | 49,924,000 | 47,047,000 | 207,870,000 | 131,212,000 |
Depreciation and Amortization | 84,513,000 | 86,636,000 | 255,656,000 | 252,188,000 |
Taxes Other Than Income Taxes | 27,527,000 | 27,315,000 | 82,931,000 | 79,272,000 |
TOTAL EXPENSES | 702,041,000 | 721,476,000 | 2,143,407,000 | 1,930,797,000 |
OPERATING INCOME (LOSS) | 147,692,000 | 142,722,000 | 404,324,000 | 455,338,000 |
Other Income (Expense): | ||||
Interest Income | 334,000 | 332,000 | 2,134,000 | 1,034,000 |
Carrying Costs Income | 2,793,000 | 3,950,000 | 6,029,000 | 17,202,000 |
Allowance for Equity Funds Used During Construction | 826,000 | 443,000 | 2,809,000 | 960,000 |
Interest Expense | -47,375,000 | -50,071,000 | -143,707,000 | -153,323,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 104,270,000 | 97,376,000 | 271,589,000 | 321,211,000 |
Income Tax Expense (Credit) | 41,645,000 | 34,185,000 | 108,554,000 | 120,377,000 |
NET INCOME (LOSS) | 62,625,000 | 63,191,000 | 163,035,000 | 200,834,000 |
Indiana Michigan Power Co [Member] | ||||
Revenues | ||||
Utility Operations | 537,453,000 | 499,078,000 | 1,518,357,000 | 1,371,070,000 |
Sales to AEP Affiliates | 73,576,000 | 71,324,000 | 159,888,000 | 192,967,000 |
Other Revenues - Affiliated | 27,322,000 | 27,034,000 | 89,962,000 | 86,797,000 |
Other Revenues | 514,000 | 768,000 | 3,552,000 | 4,453,000 |
TOTAL REVENUES | 638,865,000 | 598,204,000 | 1,771,759,000 | 1,655,287,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 140,193,000 | 137,960,000 | 330,088,000 | 347,045,000 |
Purchased Electricity for Resale | 32,976,000 | 23,399,000 | 111,602,000 | 88,797,000 |
Purchased Electricity from AEP Affiliates | 116,511,000 | 110,891,000 | 317,434,000 | 281,032,000 |
Other Operation | 136,702,000 | 141,728,000 | 414,418,000 | 411,218,000 |
Maintenance | 43,448,000 | 44,308,000 | 139,200,000 | 133,817,000 |
Depreciation and Amortization | 45,393,000 | 37,734,000 | 131,991,000 | 109,273,000 |
Taxes Other Than Income Taxes | 21,278,000 | 21,698,000 | 65,899,000 | 62,491,000 |
TOTAL EXPENSES | 536,501,000 | 517,718,000 | 1,510,632,000 | 1,433,673,000 |
OPERATING INCOME (LOSS) | 102,364,000 | 80,486,000 | 261,127,000 | 221,614,000 |
Other Income (Expense): | ||||
Interest Income | 2,360,000 | 453,000 | 7,077,000 | 2,228,000 |
Allowance for Equity Funds Used During Construction | 5,041,000 | 1,596,000 | 15,568,000 | 6,931,000 |
Interest Expense | -23,932,000 | -26,307,000 | -72,579,000 | -76,733,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 85,833,000 | 56,228,000 | 211,193,000 | 154,040,000 |
Income Tax Expense (Credit) | 27,953,000 | 16,974,000 | 69,102,000 | 45,755,000 |
NET INCOME (LOSS) | 57,880,000 | 39,254,000 | 142,091,000 | 108,285,000 |
Ohio Power Co [Member] | ||||
Revenues | ||||
Utility Operations | 959,816,000 | 1,114,339,000 | 2,710,990,000 | 3,084,657,000 |
Sales to AEP Affiliates | 313,818,000 | 229,879,000 | 873,850,000 | 584,197,000 |
Other Revenues - Affiliated | 2,715,000 | 10,207,000 | 18,138,000 | 27,297,000 |
Other Revenues | 2,827,000 | 5,391,000 | 12,982,000 | 14,638,000 |
TOTAL REVENUES | 1,279,176,000 | 1,359,816,000 | 3,615,960,000 | 3,710,789,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 396,437,000 | 426,989,000 | 1,158,389,000 | 1,095,276,000 |
Purchased Electricity for Resale | 34,568,000 | 46,146,000 | 114,911,000 | 156,384,000 |
Purchased Electricity from AEP Affiliates | 103,869,000 | 109,453,000 | 257,540,000 | 279,954,000 |
Other Operation | 159,965,000 | 189,566,000 | 481,417,000 | 481,994,000 |
Maintenance | 71,670,000 | 73,024,000 | 218,962,000 | 227,643,000 |
Asset Impairments and Other Related Charges | 0 | 0 | 154,304,000 | 0 |
Depreciation and Amortization | 94,802,000 | 130,026,000 | 289,472,000 | 401,465,000 |
Taxes Other Than Income Taxes | 105,070,000 | 105,503,000 | 310,285,000 | 309,341,000 |
TOTAL EXPENSES | 966,381,000 | 1,080,707,000 | 2,985,280,000 | 2,952,057,000 |
OPERATING INCOME (LOSS) | 312,795,000 | 279,109,000 | 630,680,000 | 758,732,000 |
Other Income (Expense): | ||||
Interest Income | 476,000 | 425,000 | 3,165,000 | 1,868,000 |
Carrying Costs Income | 2,813,000 | 7,132,000 | 9,833,000 | 14,401,000 |
Allowance for Equity Funds Used During Construction | 1,028,000 | 998,000 | 2,853,000 | 3,036,000 |
Interest Expense | -45,070,000 | -53,576,000 | -142,487,000 | -160,984,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 272,042,000 | 234,088,000 | 504,044,000 | 617,053,000 |
Income Tax Expense (Credit) | 93,141,000 | 82,578,000 | 174,313,000 | 213,290,000 |
NET INCOME (LOSS) | 178,901,000 | 151,510,000 | 329,731,000 | 403,763,000 |
Public Service Co Of Oklahoma [Member] | ||||
Revenues | ||||
Utility Operations | 408,803,000 | 364,851,000 | 986,008,000 | 968,683,000 |
Sales to AEP Affiliates | 1,659,000 | 6,865,000 | 9,186,000 | 19,377,000 |
Other Revenues | 621,000 | 1,156,000 | 2,865,000 | 2,654,000 |
TOTAL REVENUES | 411,083,000 | 372,872,000 | 998,059,000 | 990,714,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 124,763,000 | 65,195,000 | 254,314,000 | 281,746,000 |
Purchased Electricity for Resale | 55,915,000 | 75,719,000 | 179,405,000 | 145,983,000 |
Purchased Electricity from AEP Affiliates | 13,129,000 | 5,870,000 | 30,168,000 | 16,328,000 |
Other Operation | 60,566,000 | 58,975,000 | 162,032,000 | 154,834,000 |
Maintenance | 25,071,000 | 25,685,000 | 78,396,000 | 78,863,000 |
Depreciation and Amortization | 24,191,000 | 24,433,000 | 72,449,000 | 71,356,000 |
Taxes Other Than Income Taxes | 11,616,000 | 10,799,000 | 33,440,000 | 32,619,000 |
TOTAL EXPENSES | 315,251,000 | 266,676,000 | 810,204,000 | 781,729,000 |
OPERATING INCOME (LOSS) | 95,832,000 | 106,196,000 | 187,855,000 | 208,985,000 |
Other Income (Expense): | ||||
Interest Income | 25,000 | 171,000 | 1,146,000 | 1,203,000 |
Carrying Costs Income | 21,000 | 418,000 | 338,000 | 1,560,000 |
Allowance for Equity Funds Used During Construction | 852,000 | 408,000 | 2,676,000 | 1,298,000 |
Interest Expense | -13,417,000 | -13,735,000 | -40,016,000 | -42,212,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 83,313,000 | 93,458,000 | 151,999,000 | 170,834,000 |
Income Tax Expense (Credit) | 32,217,000 | 35,355,000 | 58,778,000 | 64,872,000 |
NET INCOME (LOSS) | 51,096,000 | 58,103,000 | 93,221,000 | 105,962,000 |
Southwestern Electric Power Co [Member] | ||||
Revenues | ||||
Utility Operations | 534,196,000 | 473,391,000 | 1,324,325,000 | 1,196,753,000 |
Sales to AEP Affiliates | 18,296,000 | 11,098,000 | 41,935,000 | 26,945,000 |
Other Revenues | 441,000 | 680,000 | 1,163,000 | 1,403,000 |
TOTAL REVENUES | 552,933,000 | 485,169,000 | 1,367,423,000 | 1,225,101,000 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 202,024,000 | 180,991,000 | 490,447,000 | 447,233,000 |
Purchased Electricity for Resale | 37,505,000 | 35,109,000 | 120,273,000 | 97,150,000 |
Purchased Electricity from AEP Affiliates | 815,000 | 6,121,000 | 6,757,000 | 16,965,000 |
Other Operation | 62,108,000 | 60,217,000 | 182,351,000 | 165,877,000 |
Maintenance | 24,654,000 | 27,816,000 | 84,725,000 | 78,835,000 |
Asset Impairments and Other Related Charges | 110,850,000 | 0 | 110,850,000 | 13,000,000 |
Depreciation and Amortization | 41,846,000 | 35,144,000 | 132,460,000 | 103,820,000 |
Taxes Other Than Income Taxes | 20,772,000 | 19,763,000 | 59,530,000 | 53,869,000 |
TOTAL EXPENSES | 500,574,000 | 365,161,000 | 1,187,393,000 | 976,749,000 |
OPERATING INCOME (LOSS) | 52,359,000 | 120,008,000 | 180,030,000 | 248,352,000 |
Other Income (Expense): | ||||
Allowance for Equity Funds Used During Construction | 4,872,000 | 43,401,000 | ||
Other Income | 2,457,000 | 15,255,000 | 5,048,000 | 44,572,000 |
Interest Expense | -32,614,000 | -21,498,000 | -100,151,000 | -65,210,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 22,202,000 | 113,765,000 | 84,927,000 | 227,714,000 |
Income Tax Expense (Credit) | 14,935,000 | 25,229,000 | 37,057,000 | 49,206,000 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 653,000 | 682,000 | 1,825,000 | 2,007,000 |
NET INCOME (LOSS) | 7,920,000 | 89,218,000 | 49,695,000 | 180,515,000 |
Net Income Attributable to Noncontrolling Interests | 1,058,000 | 955,000 | 3,204,000 | 3,099,000 |
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS | $6,862,000 | $88,263,000 | $46,491,000 | $177,416,000 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (Loss) (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Net Income (Loss) | $434,000,000 | $488,000,000 | $1,137,000,000 | $1,241,000,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | -1,000,000 | 13,000,000 | 13,000,000 | -8,000,000 |
Securities Available for Sale, Net of Tax | 1,000,000 | 1,000,000 | 2,000,000 | 2,000,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 7,000,000 | 7,000,000 | 16,000,000 | 22,000,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 7,000,000 | 21,000,000 | 31,000,000 | 16,000,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 441,000,000 | 509,000,000 | 1,168,000,000 | 1,257,000,000 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,000,000 | 1,000,000 | 3,000,000 | 3,000,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | 440,000,000 | 508,000,000 | 1,165,000,000 | 1,254,000,000 |
Appalachian Power Co [Member] | ||||
Net Income (Loss) | 62,625,000 | 63,191,000 | 163,035,000 | 200,834,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 22,000 | 1,719,000 | 1,369,000 | 1,746,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 359,000 | 899,000 | 1,075,000 | 2,698,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 381,000 | 2,618,000 | 2,444,000 | 4,444,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 63,006,000 | 65,809,000 | 165,479,000 | 205,278,000 |
Indiana Michigan Power Co [Member] | ||||
Net Income (Loss) | 57,880,000 | 39,254,000 | 142,091,000 | 108,285,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 244,000 | -404,000 | 3,688,000 | -5,381,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 174,000 | 278,000 | 525,000 | 835,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 418,000 | -126,000 | 4,213,000 | -4,546,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 58,298,000 | 39,128,000 | 146,304,000 | 103,739,000 |
Ohio Power Co [Member] | ||||
Net Income (Loss) | 178,901,000 | 151,510,000 | 329,731,000 | 403,763,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | -675,000 | 1,776,000 | -154,000 | 205,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 2,985,000 | 3,240,000 | 9,524,000 | 9,721,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 2,310,000 | 5,016,000 | 9,370,000 | 9,926,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 181,211,000 | 156,526,000 | 339,101,000 | 413,689,000 |
Public Service Co Of Oklahoma [Member] | ||||
Net Income (Loss) | 51,096,000 | 58,103,000 | 93,221,000 | 105,962,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | -172,000 | -53,000 | -593,000 | -465,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | -172,000 | -593,000 | -465,000 | |
TOTAL COMPREHENSIVE INCOME (LOSS) | 50,924,000 | 58,050,000 | 92,628,000 | 105,497,000 |
Southwestern Electric Power Co [Member] | ||||
Net Income (Loss) | 7,920,000 | 89,218,000 | 49,695,000 | 180,515,000 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 589,000 | 697,000 | 1,675,000 | -682,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | -64,000 | 167,000 | -191,000 | 499,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 525,000 | 864,000 | 1,484,000 | -183,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 8,445,000 | 90,082,000 | 51,179,000 | 180,332,000 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,058,000 | 955,000 | 3,204,000 | 3,099,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $7,387,000 | $89,127,000 | $47,975,000 | $177,233,000 |
Consolidated_Statements_of_Com1
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Cash Flow Hedges, Tax | $1,000,000 | $7,000,000 | $7,000,000 | $4,000,000 |
Securities Available for Sale, Tax | 0 | 0 | 1,000,000 | 1,000,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 4,000,000 | 4,000,000 | 9,000,000 | 12,000,000 |
Appalachian Power Co [Member] | ||||
Cash Flow Hedges, Tax | 12,000 | 925,000 | 737,000 | 940,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 193,000 | 484,000 | 579,000 | 1,453,000 |
Indiana Michigan Power Co [Member] | ||||
Cash Flow Hedges, Tax | 132,000 | -217,000 | 1,986,000 | -2,897,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 94,000 | 150,000 | 283,000 | 450,000 |
Ohio Power Co [Member] | ||||
Cash Flow Hedges, Tax | 363,000 | 956,000 | 83,000 | 111,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 1,607,000 | 1,745,000 | 5,128,000 | 5,234,000 |
Public Service Co Of Oklahoma [Member] | ||||
Cash Flow Hedges, Tax | 92,000 | 28,000 | 319,000 | 250,000 |
Southwestern Electric Power Co [Member] | ||||
Cash Flow Hedges, Tax | 317,000 | 376,000 | 902,000 | 367,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | $35,000 | $90,000 | $103,000 | $269,000 |
Condensed_Consolidated_Stateme
Condensed Consolidated Statements of Changes in Equity (USD $) | Total | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Common Stock [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member] | Retained Earnings [Member] | Retained Earnings [Member] | Retained Earnings [Member] | Retained Earnings [Member] | Retained Earnings [Member] | Retained Earnings [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member] | Noncontrolling Interests [Member] | Noncontrolling Interests [Member] |
Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | ||||||||||||
Beginning Balance at Dec. 31, 2011 | $14,665,000,000 | $2,936,414,000 | $1,760,980,000 | $4,450,178,000 | $892,805,000 | $1,813,757,000 | $3,274,000,000 | $260,458,000 | $56,584,000 | $321,201,000 | $157,230,000 | $135,660,000 | $5,970,000,000 | $1,573,752,000 | $980,896,000 | $1,744,099,000 | $364,037,000 | $674,606,000 | $5,890,000,000 | $1,160,747,000 | $751,721,000 | $2,582,600,000 | $364,389,000 | $1,029,915,000 | ($470,000,000) | ($58,543,000) | ($28,221,000) | ($197,722,000) | $7,149,000 | ($26,815,000) | $1,000,000 | $391,000 |
Beginning Balance, Shares at Dec. 31, 2011 | 504,000,000 | |||||||||||||||||||||||||||||||
Issuance of Common Stock, Value | 64,000,000 | 12,000,000 | 52,000,000 | |||||||||||||||||||||||||||||
Issuance of Common Stock, Shares | 2,000,000 | |||||||||||||||||||||||||||||||
Common Stock Dividends | -135,000,000 | -50,000,000 | -225,000,000 | -60,000,000 | -135,000,000 | -50,000,000 | -225,000,000 | -60,000,000 | ||||||||||||||||||||||||
Common Stock Dividends | -687,000,000 | -3,176,000 | -684,000,000 | -3,000,000 | -3,176,000 | |||||||||||||||||||||||||||
Other Changes in Equity | 7,000,000 | 8,000,000 | -1,000,000 | |||||||||||||||||||||||||||||
Net Income (Loss) | 1,238,000,000 | 177,416,000 | ||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 3,000,000 | 3,099,000 | 3,000,000 | 3,099,000 | ||||||||||||||||||||||||||||
Net Income (Loss) | 1,241,000,000 | 200,834,000 | 108,285,000 | 403,763,000 | 105,962,000 | 180,515,000 | 200,834,000 | 108,285,000 | 403,763,000 | 105,962,000 | ||||||||||||||||||||||
Other Comprehensive Income (Loss) | 16,000,000 | 4,444,000 | -4,546,000 | 9,926,000 | -465,000 | -183,000 | 16,000,000 | 4,444,000 | -4,546,000 | 9,926,000 | -465,000 | -183,000 | ||||||||||||||||||||
Ending Balance at Sep. 30, 2012 | 15,306,000,000 | 3,006,692,000 | 1,814,719,000 | 4,638,867,000 | 938,302,000 | 1,990,913,000 | 3,286,000,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 6,030,000,000 | 1,573,752,000 | 980,896,000 | 1,744,099,000 | 364,037,000 | 674,606,000 | 6,444,000,000 | 1,226,581,000 | 810,006,000 | 2,761,363,000 | 410,351,000 | 1,207,331,000 | -454,000,000 | -54,099,000 | -32,767,000 | -187,796,000 | 6,684,000 | -26,998,000 | 0 | 314,000 |
Ending Balance, Shares at Sep. 30, 2012 | 506,000,000 | |||||||||||||||||||||||||||||||
Beginning Balance at Jun. 30, 2012 | ||||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 1,000,000 | 955,000 | ||||||||||||||||||||||||||||||
Net Income (Loss) | 488,000,000 | 63,191,000 | 39,254,000 | 151,510,000 | 58,103,000 | 89,218,000 | ||||||||||||||||||||||||||
Other Comprehensive Income (Loss) | 21,000,000 | 2,618,000 | -126,000 | 5,016,000 | 864,000 | |||||||||||||||||||||||||||
Ending Balance at Sep. 30, 2012 | 15,306,000,000 | 3,006,692,000 | 1,814,719,000 | 4,638,867,000 | 938,302,000 | 1,990,913,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 1,573,752,000 | 980,896,000 | 1,744,099,000 | 364,037,000 | 674,606,000 | ||||||||||||||||
Beginning Balance at Dec. 31, 2012 | 15,237,000,000 | 3,052,562,000 | 1,803,775,000 | 4,525,709,000 | 916,278,000 | 2,021,473,000 | 3,289,000,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 6,049,000,000 | 1,573,752,000 | 980,896,000 | 1,744,099,000 | 364,037,000 | 674,606,000 | 6,236,000,000 | 1,248,250,000 | 795,178,000 | 2,626,134,000 | 388,530,000 | 1,228,806,000 | -337,000,000 | -29,898,000 | -28,883,000 | -165,725,000 | 6,481,000 | -17,860,000 | 0 | 261,000 |
Beginning Balance, Shares at Dec. 31, 2012 | 506,004,962 | 10,482,000 | ||||||||||||||||||||||||||||||
Issuance of Common Stock, Value | 61,000,000 | 10,000,000 | 51,000,000 | |||||||||||||||||||||||||||||
Issuance of Common Stock, Shares | 2,000,000 | |||||||||||||||||||||||||||||||
Distribution of Cook Coal Terminal to Parent | -2,651,000 | 19,652,000 | -22,303,000 | |||||||||||||||||||||||||||||
Common Stock Dividends | -130,000,000 | -47,500,000 | -275,000,000 | -41,250,000 | -93,750,000 | -130,000,000 | -47,500,000 | -275,000,000 | -41,250,000 | -93,750,000 | ||||||||||||||||||||||
Common Stock Dividends | -709,000,000 | -3,142,000 | -706,000,000 | -3,000,000 | -3,142,000 | |||||||||||||||||||||||||||
Other Changes in Equity | 6,000,000 | 5,000,000 | 1,000,000 | |||||||||||||||||||||||||||||
Net Income (Loss) | 1,134,000,000 | 46,491,000 | ||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 3,000,000 | 3,204,000 | 3,000,000 | 3,204,000 | ||||||||||||||||||||||||||||
Net Income (Loss) | 1,137,000,000 | 163,035,000 | 142,091,000 | 329,731,000 | 93,221,000 | 49,695,000 | 163,035,000 | 142,091,000 | 329,731,000 | 93,221,000 | ||||||||||||||||||||||
Other Comprehensive Income (Loss) | 31,000,000 | 2,444,000 | 4,213,000 | 9,370,000 | -593,000 | 1,484,000 | 31,000,000 | 2,444,000 | 4,213,000 | 9,370,000 | -593,000 | 1,484,000 | ||||||||||||||||||||
Ending Balance at Sep. 30, 2013 | 15,763,000,000 | 3,088,041,000 | 1,902,579,000 | 4,587,159,000 | 967,656,000 | 1,975,760,000 | 3,299,000,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 6,105,000,000 | 1,573,752,000 | 980,896,000 | 1,744,099,000 | 364,037,000 | 674,606,000 | 6,664,000,000 | 1,281,285,000 | 889,769,000 | 2,658,562,000 | 440,501,000 | 1,181,547,000 | -306,000,000 | -27,454,000 | -24,670,000 | -136,703,000 | 5,888,000 | -16,376,000 | 1,000,000 | 323,000 |
Ending Balance, Shares at Sep. 30, 2013 | 507,594,430 | 10,482,000 | ||||||||||||||||||||||||||||||
Beginning Balance at Jun. 30, 2013 | ||||||||||||||||||||||||||||||||
Distribution of Cook Coal Terminal to Parent | 19,652,000 | |||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Noncontrolling Interests | 1,000,000 | 1,058,000 | ||||||||||||||||||||||||||||||
Net Income (Loss) | 434,000,000 | 62,625,000 | 57,880,000 | 178,901,000 | 51,096,000 | 7,920,000 | ||||||||||||||||||||||||||
Other Comprehensive Income (Loss) | 7,000,000 | 381,000 | 418,000 | 2,310,000 | -172,000 | 525,000 | ||||||||||||||||||||||||||
Ending Balance at Sep. 30, 2013 | $15,763,000,000 | $3,088,041,000 | $1,902,579,000 | $4,587,159,000 | $967,656,000 | $1,975,760,000 | $260,458,000 | $56,584,000 | $321,201,000 | $157,230,000 | $135,660,000 | $1,573,752,000 | $980,896,000 | $364,037,000 | $674,606,000 | |||||||||||||||||
Ending Balance, Shares at Sep. 30, 2013 | 507,594,430 | 10,482,000 |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Sep. 30, 2013 | Dec. 31, 2012 | ||
Current Assets | ||||
Cash and Cash Equivalents | $147,000,000 | $279,000,000 | ||
Other Temporary Investments | 288,000,000 | 324,000,000 | ||
Accounts Receivable: | ||||
Customers | 657,000,000 | 685,000,000 | ||
Accrued Unbilled Revenues | 164,000,000 | 195,000,000 | ||
Pledged Accounts Receivable - AEP Credit | 982,000,000 | 856,000,000 | ||
Miscellaneous | 107,000,000 | 171,000,000 | ||
Allowance for Uncollectible Accounts | -54,000,000 | -36,000,000 | ||
Total Accounts Receivable | 1,856,000,000 | 1,871,000,000 | ||
Fuel | 748,000,000 | 844,000,000 | ||
Materials and Supplies | 692,000,000 | 675,000,000 | ||
Risk Management Assets | 171,000,000 | 191,000,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 81,000,000 | 88,000,000 | ||
Margin Deposits | 72,000,000 | 76,000,000 | ||
Prepayments and Other Current Assets | 262,000,000 | 241,000,000 | ||
TOTAL CURRENT ASSETS | 4,317,000,000 | 4,589,000,000 | ||
Property, Plant and Equipment | ||||
Generation | 26,172,000,000 | 26,279,000,000 | ||
Transmission | 10,256,000,000 | 9,846,000,000 | ||
Distribution | 16,067,000,000 | 15,565,000,000 | ||
Other Property, Plant and Equipment | 4,060,000,000 | 3,945,000,000 | ||
Construction Work in Progress | 2,489,000,000 | 1,819,000,000 | ||
Total Property, Plant and Equipment | 59,044,000,000 | 57,454,000,000 | ||
Accumulated Depreciation and Amortization | 19,174,000,000 | 18,691,000,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 39,870,000,000 | 38,763,000,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 5,038,000,000 | 5,106,000,000 | ||
Securitized Transition Assets | 2,080,000,000 | 2,117,000,000 | ||
Spent Nuclear Fuel and Decommissioning Trusts | 1,839,000,000 | 1,706,000,000 | ||
Goodwill | 91,000,000 | 91,000,000 | ||
Long-term Risk Management Assets | 314,000,000 | 368,000,000 | ||
Deferred Charges and Other Noncurrent Assets | 1,414,000,000 | 1,627,000,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 10,776,000,000 | 11,015,000,000 | ||
TOTAL ASSETS | 54,963,000,000 | 54,367,000,000 | ||
Current Liabilities | ||||
Accounts Payable | 1,044,000,000 | 1,169,000,000 | ||
Short-term Debt: | ||||
Securitized Debt for Receivable - AEP Credit | 700,000,000 | [1] | 657,000,000 | [1] |
Other Short-term Debt | 518,000,000 | 324,000,000 | ||
Total Short-term Debt | 1,218,000,000 | 981,000,000 | ||
Long-term Debt Due Within One Year | 1,366,000,000 | 2,171,000,000 | ||
Risk Management Liabilities | 102,000,000 | 155,000,000 | ||
Customer Deposits | 298,000,000 | 316,000,000 | ||
Accrued Taxes | 590,000,000 | 747,000,000 | ||
Accrued Interest | 219,000,000 | 269,000,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 14,000,000 | 47,000,000 | ||
Other Current Liabilities | 841,000,000 | 968,000,000 | ||
TOTAL CURRENT LIABILITIES | 5,692,000,000 | 6,823,000,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 16,202,000,000 | 15,586,000,000 | ||
Long-term Risk Management Liabilities | 182,000,000 | 214,000,000 | ||
Deferred Income Taxes | 9,871,000,000 | 9,252,000,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 3,640,000,000 | 3,544,000,000 | ||
Asset Retirement Obligations | 1,736,000,000 | 1,696,000,000 | ||
Employee Benefits and Pension Obligations | 986,000,000 | 1,075,000,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 891,000,000 | 940,000,000 | ||
TOTAL NONCURRENT LIABILITIES | 33,508,000,000 | 32,307,000,000 | ||
TOTAL LIABILITIES | 39,200,000,000 | 39,130,000,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 3,299,000,000 | 3,289,000,000 | ||
Paid-in Capital | 6,105,000,000 | 6,049,000,000 | ||
Retained Earnings | 6,664,000,000 | 6,236,000,000 | ||
Accumulated Other Comprehensive Income (Loss) | -306,000,000 | -337,000,000 | ||
TOTAL COMMON SHAREHOLDER'S EQUITY | 15,762,000,000 | 15,237,000,000 | ||
Noncontrolling Interests | 1,000,000 | 0 | ||
TOTAL EQUITY | 15,763,000,000 | 15,237,000,000 | ||
TOTAL LIABILITIES AND EQUITY | 54,963,000,000 | 54,367,000,000 | ||
Appalachian Power Co [Member] | ||||
Current Assets | ||||
Cash and Cash Equivalents | 4,130,000 | 3,576,000 | ||
Advances to Affiliates | 23,424,000 | 23,024,000 | ||
Accounts Receivable: | ||||
Customers | 130,168,000 | 158,380,000 | ||
Affiliated Companies | 83,218,000 | 96,213,000 | ||
Accrued Unbilled Revenues | 46,592,000 | 70,825,000 | ||
Miscellaneous | 1,744,000 | 1,344,000 | ||
Allowance for Uncollectible Accounts | -2,361,000 | -6,087,000 | ||
Total Accounts Receivable | 259,361,000 | 320,675,000 | ||
Fuel | 177,586,000 | 185,813,000 | ||
Materials and Supplies | 108,341,000 | 105,208,000 | ||
Risk Management Assets | 24,550,000 | 30,960,000 | ||
Accrued Tax Benefits | 42,735,000 | 50,032,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 48,880,000 | 74,906,000 | ||
Prepayments and Other Current Assets | 15,986,000 | 18,690,000 | ||
TOTAL CURRENT ASSETS | 704,993,000 | 812,884,000 | ||
Property, Plant and Equipment | ||||
Generation | 5,688,679,000 | 5,632,665,000 | ||
Transmission | 2,066,088,000 | 2,042,144,000 | ||
Distribution | 3,075,781,000 | 2,991,898,000 | ||
Other Property, Plant and Equipment | 386,192,000 | 373,327,000 | ||
Construction Work in Progress | 250,040,000 | 266,247,000 | ||
Total Property, Plant and Equipment | 11,466,780,000 | 11,306,281,000 | ||
Accumulated Depreciation and Amortization | 3,307,175,000 | 3,196,639,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 8,159,605,000 | 8,109,642,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 1,339,713,000 | 1,435,704,000 | ||
Long-term Risk Management Assets | 20,839,000 | 34,360,000 | ||
Deferred Charges and Other Noncurrent Assets | 96,016,000 | 115,078,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 1,456,568,000 | 1,585,142,000 | ||
TOTAL ASSETS | 10,321,166,000 | 10,507,668,000 | ||
Current Liabilities | ||||
Advances from Affiliates | 276,776,000 | 173,965,000 | ||
Accounts Payable | 141,492,000 | 195,203,000 | ||
Affiliated Companies | 98,211,000 | 137,088,000 | ||
Short-term Debt: | ||||
Long-term Debt Due Within One Year | 229,682,000 | 574,679,000 | ||
Risk Management Liabilities | 11,641,000 | 16,698,000 | ||
Customer Deposits | 66,377,000 | 67,339,000 | ||
Deferred Income Taxes | 21,263,000 | 11,715,000 | ||
Accrued Taxes | 66,994,000 | 74,967,000 | ||
Accrued Interest | 58,381,000 | 51,442,000 | ||
Other Current Liabilities | 88,687,000 | 110,657,000 | ||
TOTAL CURRENT LIABILITIES | 1,059,504,000 | 1,413,753,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 3,198,235,000 | 3,127,763,000 | ||
Long-term Risk Management Liabilities | 12,081,000 | 18,476,000 | ||
Deferred Income Taxes | 1,992,385,000 | 1,928,683,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 627,360,000 | 607,680,000 | ||
Employee Benefits and Pension Obligations | 194,237,000 | 204,207,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 149,323,000 | 154,544,000 | ||
TOTAL NONCURRENT LIABILITIES | 6,173,621,000 | 6,041,353,000 | ||
TOTAL LIABILITIES | 7,233,125,000 | 7,455,106,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 260,458,000 | 260,458,000 | ||
Paid-in Capital | 1,573,752,000 | 1,573,752,000 | ||
Retained Earnings | 1,281,285,000 | 1,248,250,000 | ||
Accumulated Other Comprehensive Income (Loss) | -27,454,000 | -29,898,000 | ||
TOTAL EQUITY | 3,088,041,000 | 3,052,562,000 | ||
TOTAL LIABILITIES AND EQUITY | 10,321,166,000 | 10,507,668,000 | ||
Indiana Michigan Power Co [Member] | ||||
Current Assets | ||||
Cash and Cash Equivalents | 1,798,000 | 1,562,000 | ||
Advances to Affiliates | 322,476,000 | 116,977,000 | ||
Accounts Receivable: | ||||
Customers | 52,482,000 | 61,776,000 | ||
Affiliated Companies | 67,744,000 | 79,886,000 | ||
Accrued Unbilled Revenues | 16,469,000 | 11,218,000 | ||
Miscellaneous | 5,291,000 | 12,260,000 | ||
Allowance for Uncollectible Accounts | -186,000 | -229,000 | ||
Total Accounts Receivable | 141,800,000 | 164,911,000 | ||
Fuel | 71,372,000 | 53,406,000 | ||
Materials and Supplies | 187,040,000 | 195,147,000 | ||
Risk Management Assets | 16,150,000 | 26,974,000 | ||
Deferred Cook Plant Fire Costs | 0 | 80,000,000 | ||
Prepayments and Other Current Assets | 39,328,000 | 83,270,000 | ||
TOTAL CURRENT ASSETS | 779,964,000 | 722,247,000 | ||
Property, Plant and Equipment | ||||
Generation | 4,177,462,000 | 4,062,733,000 | ||
Transmission | 1,311,364,000 | 1,278,236,000 | ||
Distribution | 1,594,559,000 | 1,553,358,000 | ||
Other Property, Plant and Equipment | 729,516,000 | 725,313,000 | ||
Construction Work in Progress | 388,835,000 | 341,063,000 | ||
Total Property, Plant and Equipment | 8,201,736,000 | 7,960,703,000 | ||
Accumulated Depreciation and Amortization | 3,301,177,000 | 3,232,135,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 4,900,559,000 | 4,728,568,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 567,402,000 | 540,019,000 | ||
Spent Nuclear Fuel and Decommissioning Trusts | 1,839,118,000 | 1,705,772,000 | ||
Long-term Risk Management Assets | 13,733,000 | 23,569,000 | ||
Deferred Charges and Other Noncurrent Assets | 87,016,000 | 111,364,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 2,507,269,000 | 2,380,724,000 | ||
TOTAL ASSETS | 8,187,792,000 | 7,831,539,000 | ||
Current Liabilities | ||||
Accounts Payable | 120,821,000 | 208,701,000 | ||
Affiliated Companies | 64,779,000 | 104,631,000 | ||
Short-term Debt: | ||||
Long-term Debt Due Within One Year | 224,859,000 | 203,953,000 | ||
Risk Management Liabilities | 9,268,000 | 31,517,000 | ||
Customer Deposits | 30,702,000 | 31,142,000 | ||
Accrued Taxes | 45,223,000 | 67,675,000 | ||
Accrued Interest | 18,855,000 | 26,859,000 | ||
Other Current Liabilities | 131,823,000 | 122,053,000 | ||
TOTAL CURRENT LIABILITIES | 646,330,000 | 796,531,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 2,046,754,000 | 1,853,713,000 | ||
Long-term Risk Management Liabilities | 8,307,000 | 13,898,000 | ||
Deferred Income Taxes | 1,120,947,000 | 1,019,160,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 1,042,494,000 | 948,292,000 | ||
Asset Retirement Obligations | 1,234,540,000 | 1,192,313,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 185,841,000 | 203,857,000 | ||
TOTAL NONCURRENT LIABILITIES | 5,638,883,000 | 5,231,233,000 | ||
TOTAL LIABILITIES | 6,285,213,000 | 6,027,764,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 56,584,000 | 56,584,000 | ||
Paid-in Capital | 980,896,000 | 980,896,000 | ||
Retained Earnings | 889,769,000 | 795,178,000 | ||
Accumulated Other Comprehensive Income (Loss) | -24,670,000 | -28,883,000 | ||
TOTAL EQUITY | 1,902,579,000 | 1,803,775,000 | ||
TOTAL LIABILITIES AND EQUITY | 8,187,792,000 | 7,831,539,000 | ||
Ohio Power Co [Member] | ||||
Current Assets | ||||
Cash and Cash Equivalents | 4,341,000 | 3,640,000 | ||
Advances to Affiliates | 10,126,000 | 116,422,000 | ||
Accounts Receivable: | ||||
Customers | 83,382,000 | 135,954,000 | ||
Affiliated Companies | 147,471,000 | 176,590,000 | ||
Accrued Unbilled Revenues | 38,753,000 | 57,887,000 | ||
Miscellaneous | 6,683,000 | 9,327,000 | ||
Allowance for Uncollectible Accounts | -26,966,000 | -129,000 | ||
Total Accounts Receivable | 249,323,000 | 379,629,000 | ||
Fuel | 251,888,000 | 328,840,000 | ||
Materials and Supplies | 173,397,000 | 186,269,000 | ||
Risk Management Assets | 34,178,000 | 44,313,000 | ||
Accrued Tax Benefits | 947,000 | 17,785,000 | ||
Prepayments and Other Current Assets | 50,199,000 | 26,807,000 | ||
TOTAL CURRENT ASSETS | 774,399,000 | 1,103,705,000 | ||
Property, Plant and Equipment | ||||
Generation | 8,392,967,000 | 8,673,296,000 | ||
Transmission | 2,034,958,000 | 2,013,737,000 | ||
Distribution | 3,815,303,000 | 3,722,745,000 | ||
Other Property, Plant and Equipment | 566,007,000 | 571,154,000 | ||
Construction Work in Progress | 440,199,000 | 354,497,000 | ||
Total Property, Plant and Equipment | 15,249,434,000 | 15,335,429,000 | ||
Accumulated Depreciation and Amortization | 5,220,979,000 | 5,242,805,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 10,028,455,000 | 10,092,624,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 1,455,176,000 | 1,420,966,000 | ||
Securitized Transition Assets | 136,566,000 | 0 | ||
Long-term Risk Management Assets | 28,594,000 | 48,288,000 | ||
Deferred Charges and Other Noncurrent Assets | 133,024,000 | 320,026,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 1,753,360,000 | 1,789,280,000 | ||
TOTAL ASSETS | 12,556,214,000 | 12,985,609,000 | ||
Current Liabilities | ||||
Advances from Affiliates | 1,063,000 | 0 | ||
Accounts Payable | 249,663,000 | 276,220,000 | ||
Affiliated Companies | 99,322,000 | 153,222,000 | ||
Short-term Debt: | ||||
Long-term Debt Due Within One Year | 553,516,000 | 856,000,000 | ||
Risk Management Liabilities | 16,431,000 | 24,155,000 | ||
Accrued Taxes | 261,496,000 | 467,309,000 | ||
Accrued Interest | 54,603,000 | 63,560,000 | ||
Other Current Liabilities | 201,018,000 | 263,638,000 | ||
TOTAL CURRENT LIABILITIES | 1,437,112,000 | 2,104,104,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 2,945,058,000 | 2,804,440,000 | ||
Long-term Debt - Affiliated | 200,000,000 | 200,000,000 | ||
Long-term Risk Management Liabilities | 16,577,000 | 25,965,000 | ||
Deferred Income Taxes | 2,489,349,000 | 2,345,850,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 444,216,000 | 451,071,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 436,743,000 | 528,470,000 | ||
TOTAL NONCURRENT LIABILITIES | 6,531,943,000 | 6,355,796,000 | ||
TOTAL LIABILITIES | 7,969,055,000 | 8,459,900,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 321,201,000 | 321,201,000 | ||
Paid-in Capital | 1,744,099,000 | 1,744,099,000 | ||
Retained Earnings | 2,658,562,000 | 2,626,134,000 | ||
Accumulated Other Comprehensive Income (Loss) | -136,703,000 | -165,725,000 | ||
TOTAL EQUITY | 4,587,159,000 | 4,525,709,000 | ||
TOTAL LIABILITIES AND EQUITY | 12,556,214,000 | 12,985,609,000 | ||
Public Service Co Of Oklahoma [Member] | ||||
Current Assets | ||||
Cash and Cash Equivalents | 2,000,000 | 1,367,000 | ||
Advances to Affiliates | 19,442,000 | 10,558,000 | ||
Accounts Receivable: | ||||
Customers | 30,787,000 | 31,047,000 | ||
Affiliated Companies | 20,448,000 | 24,751,000 | ||
Miscellaneous | 4,409,000 | 6,216,000 | ||
Allowance for Uncollectible Accounts | -956,000 | -872,000 | ||
Total Accounts Receivable | 54,688,000 | 61,142,000 | ||
Fuel | 18,202,000 | 22,085,000 | ||
Materials and Supplies | 52,190,000 | 52,183,000 | ||
Risk Management Assets | 852,000 | 509,000 | ||
Deferred Income Tax Benefits | 5,713,000 | 7,183,000 | ||
Accrued Tax Benefits | 10,628,000 | 11,812,000 | ||
Prepayments and Other Current Assets | 6,908,000 | 7,633,000 | ||
TOTAL CURRENT ASSETS | 170,623,000 | 174,472,000 | ||
Property, Plant and Equipment | ||||
Generation | 1,381,290,000 | 1,346,530,000 | ||
Transmission | 724,125,000 | 706,917,000 | ||
Distribution | 1,937,654,000 | 1,859,557,000 | ||
Other Property, Plant and Equipment | 219,015,000 | 210,549,000 | ||
Construction Work in Progress | 118,879,000 | 95,170,000 | ||
Total Property, Plant and Equipment | 4,380,963,000 | 4,218,723,000 | ||
Accumulated Depreciation and Amortization | 1,321,843,000 | 1,278,941,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 3,059,120,000 | 2,939,782,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 185,856,000 | 202,328,000 | ||
Long-term Risk Management Assets | 149,000 | 31,000 | ||
Deferred Charges and Other Noncurrent Assets | 17,217,000 | 8,560,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 203,222,000 | 210,919,000 | ||
TOTAL ASSETS | 3,432,965,000 | 3,325,173,000 | ||
Current Liabilities | ||||
Accounts Payable | 106,997,000 | 87,050,000 | ||
Affiliated Companies | 32,646,000 | 36,189,000 | ||
Short-term Debt: | ||||
Long-term Debt Due Within One Year | 34,111,000 | 764,000 | ||
Risk Management Liabilities | 1,388,000 | 5,848,000 | ||
Customer Deposits | 45,653,000 | 46,533,000 | ||
Accrued Taxes | 55,923,000 | 28,024,000 | ||
Accrued Interest | 15,383,000 | 12,654,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 144,000 | 7,945,000 | ||
Other Current Liabilities | 47,311,000 | 50,684,000 | ||
TOTAL CURRENT LIABILITIES | 339,556,000 | 275,691,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 915,715,000 | 949,107,000 | ||
Long-term Risk Management Liabilities | 0 | 31,000 | ||
Deferred Income Taxes | 814,719,000 | 740,676,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 324,329,000 | 344,817,000 | ||
Employee Benefits and Pension Obligations | 33,884,000 | 34,906,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 37,106,000 | 63,667,000 | ||
TOTAL NONCURRENT LIABILITIES | 2,125,753,000 | 2,133,204,000 | ||
TOTAL LIABILITIES | 2,465,309,000 | 2,408,895,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 157,230,000 | 157,230,000 | ||
Paid-in Capital | 364,037,000 | 364,037,000 | ||
Retained Earnings | 440,501,000 | 388,530,000 | ||
Accumulated Other Comprehensive Income (Loss) | 5,888,000 | 6,481,000 | ||
TOTAL EQUITY | 967,656,000 | 916,278,000 | ||
TOTAL LIABILITIES AND EQUITY | 3,432,965,000 | 3,325,173,000 | ||
Southwestern Electric Power Co [Member] | ||||
Current Assets | ||||
Cash and Cash Equivalents | 17,651,000 | 2,036,000 | ||
Advances to Affiliates | 18,634,000 | 153,829,000 | ||
Accounts Receivable: | ||||
Customers | 59,408,000 | 39,349,000 | ||
Affiliated Companies | 26,597,000 | 26,288,000 | ||
Miscellaneous | 22,350,000 | 35,514,000 | ||
Allowance for Uncollectible Accounts | -2,034,000 | -2,041,000 | ||
Total Accounts Receivable | 106,321,000 | 99,110,000 | ||
Fuel | 121,443,000 | 134,234,000 | ||
Materials and Supplies | 73,365,000 | 69,212,000 | ||
Risk Management Assets | 402,000 | 695,000 | ||
Deferred Income Tax Benefits | 99,362,000 | 101,403,000 | ||
Accrued Tax Benefits | 7,015,000 | 9,616,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 21,430,000 | 8,527,000 | ||
Prepayments and Other Current Assets | 18,673,000 | 16,489,000 | ||
TOTAL CURRENT ASSETS | 484,296,000 | 595,151,000 | ||
Property, Plant and Equipment | ||||
Generation | 3,813,995,000 | 3,888,230,000 | ||
Transmission | 1,141,848,000 | 1,115,795,000 | ||
Distribution | 1,807,252,000 | 1,758,988,000 | ||
Other Property, Plant and Equipment | 699,918,000 | 688,254,000 | ||
Construction Work in Progress | 223,860,000 | 99,783,000 | ||
Total Property, Plant and Equipment | 7,686,873,000 | 7,551,050,000 | ||
Accumulated Depreciation and Amortization | 2,378,225,000 | 2,284,258,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,308,648,000 | 5,266,792,000 | ||
Other Noncurrent Assets | ||||
Regulatory Assets | 375,581,000 | 403,278,000 | ||
Long-term Risk Management Assets | 21,000 | 0 | ||
Deferred Charges and Other Noncurrent Assets | 81,848,000 | 76,432,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 457,450,000 | 479,710,000 | ||
TOTAL ASSETS | 6,250,394,000 | 6,341,653,000 | ||
Current Liabilities | ||||
Accounts Payable | 132,265,000 | 126,768,000 | ||
Affiliated Companies | 39,657,000 | 62,835,000 | ||
Short-term Debt: | ||||
Other Short-term Debt | 0 | 2,603,000 | ||
Long-term Debt Due Within One Year | 3,250,000 | 3,250,000 | ||
Risk Management Liabilities | 296,000 | 1,128,000 | ||
Customer Deposits | 55,832,000 | 69,393,000 | ||
Accrued Taxes | 64,436,000 | 31,532,000 | ||
Accrued Interest | 19,234,000 | 43,950,000 | ||
Obligations Under Capital Leases | 17,905,000 | 17,599,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 5,562,000 | 16,761,000 | ||
Other Current Liabilities | 63,921,000 | 64,997,000 | ||
TOTAL CURRENT LIABILITIES | 402,358,000 | 440,816,000 | ||
Noncurrent Liabilities | ||||
Long-term Debt | 2,039,994,000 | 2,042,978,000 | ||
Deferred Income Taxes | 1,095,691,000 | 1,075,551,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 471,953,000 | 476,471,000 | ||
Asset Retirement Obligations | 87,565,000 | 78,017,000 | ||
Employee Benefits and Pension Obligations | 31,129,000 | 38,240,000 | ||
Obligations Under Capital Leases | 104,175,000 | 114,161,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 41,769,000 | 53,946,000 | ||
TOTAL NONCURRENT LIABILITIES | 3,872,276,000 | 3,879,364,000 | ||
TOTAL LIABILITIES | 4,274,634,000 | 4,320,180,000 | ||
Rate Matters | ||||
Commitments and Contingencies | ||||
Equity | ||||
Common Stock | 135,660,000 | 135,660,000 | ||
Paid-in Capital | 674,606,000 | 674,606,000 | ||
Retained Earnings | 1,181,547,000 | 1,228,806,000 | ||
Accumulated Other Comprehensive Income (Loss) | -16,376,000 | -17,860,000 | ||
TOTAL COMMON SHAREHOLDER'S EQUITY | 1,975,437,000 | 2,021,212,000 | ||
Noncontrolling Interests | 323,000 | 261,000 | ||
TOTAL EQUITY | 1,975,760,000 | 2,021,473,000 | ||
TOTAL LIABILITIES AND EQUITY | $6,250,394,000 | $6,341,653,000 | ||
[1] | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. |
Condensed_Consolidated_Balance1
Condensed Consolidated Balance Sheets (Parenthetical) (USD $) | Sep. 30, 2013 | Dec. 31, 2012 |
Current Assets | ||
Cash and Cash Equivalents | $147,000,000 | $279,000,000 |
Other Temporary Investments | 288,000,000 | 324,000,000 |
Fuel | 748,000,000 | 844,000,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 4,060,000,000 | 3,945,000,000 |
Accumulated Depreciation and Amortization | 19,174,000,000 | 18,691,000,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 1,366,000,000 | 2,171,000,000 |
Noncurrent Liabilities | ||
Long-term Debt | 16,202,000,000 | 15,586,000,000 |
Equity | ||
Common Stock, Par Value Per Share | $6.50 | $6.50 |
Common Stock, Shares Authorized | 600,000,000 | 600,000,000 |
Common Stock, Shares, Issued | 507,594,430 | 506,004,962 |
Treasury Stock, Shares | 20,336,592 | 20,336,592 |
Appalachian Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 4,130,000 | 3,576,000 |
Fuel | 177,586,000 | 185,813,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 386,192,000 | 373,327,000 |
Accumulated Depreciation and Amortization | 3,307,175,000 | 3,196,639,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 229,682,000 | 574,679,000 |
Noncurrent Liabilities | ||
Long-term Debt | 3,198,235,000 | 3,127,763,000 |
Equity | ||
Common Stock, No Par Value | ||
Common Stock, Shares Authorized | 30,000,000 | 30,000,000 |
Common Stock, Shares Outstanding | 13,499,500 | 13,499,500 |
Indiana Michigan Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 1,798,000 | 1,562,000 |
Fuel | 71,372,000 | 53,406,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 729,516,000 | 725,313,000 |
Accumulated Depreciation and Amortization | 3,301,177,000 | 3,232,135,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 224,859,000 | 203,953,000 |
Noncurrent Liabilities | ||
Long-term Debt | 2,046,754,000 | 1,853,713,000 |
Equity | ||
Common Stock, No Par Value | ||
Common Stock, Shares Authorized | 2,500,000 | 2,500,000 |
Common Stock, Shares Outstanding | 1,400,000 | 1,400,000 |
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | ||
Current Liabilities | ||
Long-term Debt Due Within One Year | 137,636,000 | 119,890,000 |
Ohio Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 4,341,000 | 3,640,000 |
Fuel | 251,888,000 | 328,840,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 566,007,000 | 571,154,000 |
Accumulated Depreciation and Amortization | 5,220,979,000 | 5,242,805,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 553,516,000 | 856,000,000 |
Noncurrent Liabilities | ||
Long-term Debt | 2,945,058,000 | 2,804,440,000 |
Equity | ||
Common Stock, No Par Value | ||
Common Stock, Shares Authorized | 40,000,000 | 40,000,000 |
Common Stock, Shares Outstanding | 27,952,473 | 27,952,473 |
Public Service Co Of Oklahoma [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 2,000,000 | 1,367,000 |
Fuel | 18,202,000 | 22,085,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 219,015,000 | 210,549,000 |
Accumulated Depreciation and Amortization | 1,321,843,000 | 1,278,941,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 34,111,000 | 764,000 |
Noncurrent Liabilities | ||
Long-term Debt | 915,715,000 | 949,107,000 |
Equity | ||
Common Stock, Par Value Per Share | $15 | $15 |
Common Stock, Shares Authorized | 11,000,000 | 11,000,000 |
Common Stock, Shares, Issued | 10,482,000 | 10,482,000 |
Common Stock, Shares Outstanding | 9,013,000 | 9,013,000 |
Southwestern Electric Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 17,651,000 | 2,036,000 |
Fuel | 121,443,000 | 134,234,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 699,918,000 | 688,254,000 |
Accumulated Depreciation and Amortization | 2,378,225,000 | 2,284,258,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 3,250,000 | 3,250,000 |
Noncurrent Liabilities | ||
Long-term Debt | 2,039,994,000 | 2,042,978,000 |
Equity | ||
Common Stock, Par Value Per Share | $18 | $18 |
Common Stock, Shares Authorized | 7,600,000 | 7,600,000 |
Common Stock, Shares Outstanding | 7,536,640 | 7,536,640 |
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 14,207,000 | |
Fuel | 32,992,000 | 42,084,000 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 288,494,000 | 287,032,000 |
Accumulated Depreciation and Amortization | 130,141,000 | 116,597,000 |
AEP Subsidiaries [Member] | ||
Current Assets | ||
Other Temporary Investments | 275,000,000 | 311,000,000 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 433,000,000 | 367,000,000 |
Noncurrent Liabilities | ||
Long-term Debt | $2,222,000,000 | $2,227,000,000 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Cash Flows (USD $) | 9 Months Ended | |
Sep. 30, 2013 | Sep. 30, 2012 | |
Operating Activities | ||
Net Income (Loss) | $1,137,000,000 | $1,241,000,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 1,310,000,000 | 1,353,000,000 |
Deferred Income Taxes | 582,000,000 | 592,000,000 |
Asset Impairments and Other Related Charges | 298,000,000 | 13,000,000 |
Carrying Costs Income | -20,000,000 | -42,000,000 |
Allowance for Equity Funds Used During Construction | -51,000,000 | -70,000,000 |
Mark-to-Market of Risk Management Contracts | 29,000,000 | 70,000,000 |
Amortization of Nuclear Fuel | 101,000,000 | 100,000,000 |
Pension Contributions to Qualified Plan Trust | 0 | -100,000,000 |
Property Taxes | 191,000,000 | 181,000,000 |
Fuel Over/Under-Recovery, Net | 38,000,000 | 133,000,000 |
Deferral of Ohio Capacity Costs, Net | -157,000,000 | -22,000,000 |
Change in Other Noncurrent Assets | -35,000,000 | -173,000,000 |
Change in Other Noncurrent Liabilities | 16,000,000 | 119,000,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 4,000,000 | -4,000,000 |
Fuel, Materials and Supplies | 72,000,000 | -169,000,000 |
Accounts Payable | -28,000,000 | -135,000,000 |
Accrued Taxes, Net | -278,000,000 | -130,000,000 |
Other Current Assets | -5,000,000 | -28,000,000 |
Other Current Liabilities | -164,000,000 | -17,000,000 |
Net Cash Flows from (Used for) Operating Activities | 3,040,000,000 | 2,912,000,000 |
Investing Activities | ||
Construction Expenditures | -2,481,000,000 | -2,108,000,000 |
Change in Other Temporary Investments, Net | 53,000,000 | 19,000,000 |
Purchases of Investment Securities | -693,000,000 | -745,000,000 |
Sales of Investment Securities | 635,000,000 | 699,000,000 |
Acquisitions of Nuclear Fuel | -110,000,000 | -13,000,000 |
Acquisitions of Assets/Businesses | -6,000,000 | -89,000,000 |
Insurance Proceeds Related to Cook Plant Fire | 72,000,000 | 0 |
Proceeds from Sales of Assets | 14,000,000 | 13,000,000 |
Other Investing Activities | -4,000,000 | -57,000,000 |
Net Cash Flows from (Used for) Investing Activities | -2,520,000,000 | -2,281,000,000 |
Financing Activities | ||
Issuance of Common Stock, Net | 61,000,000 | 64,000,000 |
Issuance of Long-term Debt | 2,087,000,000 | 1,600,000,000 |
Credit Facility Borrowings | 17,000,000 | 21,000,000 |
Change in Short-term Debt, Net | 240,000,000 | -417,000,000 |
Retirement of Long-term Debt | -2,281,000,000 | -904,000,000 |
Credit Facility Repayments | -20,000,000 | -38,000,000 |
Principal Payments for Capital Lease Obligations | -53,000,000 | -53,000,000 |
Dividends Paid on Common Stock | -709,000,000 | -687,000,000 |
Other Financing Activities | 6,000,000 | 5,000,000 |
Net Cash Flows from (Used for) Financing Activities | -652,000,000 | -409,000,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | -132,000,000 | 222,000,000 |
Cash and Cash Equivalents at Beginning of Period | 279,000,000 | 221,000,000 |
Cash and Cash Equivalents at End of Period | 147,000,000 | 443,000,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 702,000,000 | 698,000,000 |
Net Cash Paid (Received) for Income Taxes | -64,000,000 | -44,000,000 |
Noncash Acquisitions Under Capital Leases | 53,000,000 | 46,000,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 363,000,000 | 325,000,000 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | 0 | 43,000,000 |
Noncash Assumption of Liabilities Related to Acquisitions | 0 | 56,000,000 |
Appalachian Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 163,035,000 | 200,834,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 255,656,000 | 252,188,000 |
Deferred Income Taxes | 89,501,000 | 84,850,000 |
Carrying Costs Income | -6,029,000 | -17,202,000 |
Deferral of Storm Costs | 34,364,000 | -57,638,000 |
Allowance for Equity Funds Used During Construction | -2,809,000 | -960,000 |
Mark-to-Market of Risk Management Contracts | 9,409,000 | 10,284,000 |
Property Taxes | 21,940,000 | 20,056,000 |
Fuel Over/Under-Recovery, Net | 46,009,000 | 61,404,000 |
Change in Other Noncurrent Assets | -19,784,000 | -35,501,000 |
Change in Other Noncurrent Liabilities | 10,199,000 | 7,155,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 62,363,000 | 94,528,000 |
Fuel, Materials and Supplies | 5,094,000 | -44,007,000 |
Accounts Payable | -76,665,000 | -27,443,000 |
Accrued Taxes, Net | -726,000 | -709,000 |
Other Current Assets | 1,970,000 | 1,754,000 |
Other Current Liabilities | -14,820,000 | 12,128,000 |
Net Cash Flows from (Used for) Operating Activities | 578,707,000 | 561,721,000 |
Investing Activities | ||
Construction Expenditures | -272,433,000 | -323,866,000 |
Change in Advances to Affiliates, Net | -400,000 | -759,000 |
Other Investing Activities | 103,000 | 7,880,000 |
Net Cash Flows from (Used for) Investing Activities | -272,730,000 | -316,745,000 |
Financing Activities | ||
Issuance of Long-term Debt | 69,346,000 | 339,396,000 |
Change in Advances from Affiliates, Net | 102,811,000 | -80,674,000 |
Retirement of Long-term Debt | -345,021,000 | -364,868,000 |
Principal Payments for Capital Lease Obligations | -4,049,000 | -4,873,000 |
Dividends Paid on Common Stock | -130,000,000 | -135,000,000 |
Other Financing Activities | 1,490,000 | 301,000 |
Net Cash Flows from (Used for) Financing Activities | -305,423,000 | -245,718,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 554,000 | -742,000 |
Cash and Cash Equivalents at Beginning of Period | 3,576,000 | 2,317,000 |
Cash and Cash Equivalents at End of Period | 4,130,000 | 1,575,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 131,600,000 | 137,992,000 |
Net Cash Paid (Received) for Income Taxes | -3,746,000 | 10,870,000 |
Noncash Acquisitions Under Capital Leases | 3,440,000 | 2,338,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 43,802,000 | 59,041,000 |
Indiana Michigan Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 142,091,000 | 108,285,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 131,991,000 | 109,273,000 |
Deferred Income Taxes | 84,067,000 | 46,365,000 |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expense, Net | -15,450,000 | 2,598,000 |
Allowance for Equity Funds Used During Construction | -15,568,000 | -6,931,000 |
Mark-to-Market of Risk Management Contracts | 12,995,000 | 9,882,000 |
Amortization of Nuclear Fuel | 101,316,000 | 100,435,000 |
Fuel Over/Under-Recovery, Net | 6,459,000 | 2,867,000 |
Change in Other Noncurrent Assets | -718,000 | 14,214,000 |
Change in Other Noncurrent Liabilities | 25,249,000 | 46,263,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 23,111,000 | 25,415,000 |
Fuel, Materials and Supplies | -9,859,000 | 7,315,000 |
Accounts Payable | -35,517,000 | -75,799,000 |
Accrued Taxes, Net | -8,987,000 | 7,398,000 |
Other Current Assets | 18,948,000 | -3,368,000 |
Other Current Liabilities | -4,130,000 | 39,541,000 |
Net Cash Flows from (Used for) Operating Activities | 455,998,000 | 433,753,000 |
Investing Activities | ||
Construction Expenditures | -360,668,000 | -212,006,000 |
Change in Advances to Affiliates, Net | -205,499,000 | -189,054,000 |
Purchases of Investment Securities | -675,727,000 | -744,131,000 |
Sales of Investment Securities | 635,256,000 | 698,567,000 |
Acquisitions of Nuclear Fuel | -109,598,000 | -12,545,000 |
Insurance Proceeds Related to Cook Plant Fire | 72,000,000 | 0 |
Other Investing Activities | 27,888,000 | 29,714,000 |
Net Cash Flows from (Used for) Investing Activities | -616,348,000 | -429,455,000 |
Financing Activities | ||
Issuance of Long-term Debt | 348,892,000 | 128,228,000 |
Retirement of Long-term Debt | -137,544,000 | -78,062,000 |
Principal Payments for Capital Lease Obligations | -4,112,000 | -4,929,000 |
Dividends Paid on Common Stock | -47,500,000 | -50,000,000 |
Other Financing Activities | 850,000 | 212,000 |
Net Cash Flows from (Used for) Financing Activities | 160,586,000 | -4,551,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 236,000 | -253,000 |
Cash and Cash Equivalents at Beginning of Period | 1,562,000 | 1,020,000 |
Cash and Cash Equivalents at End of Period | 1,798,000 | 767,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 76,468,000 | 79,158,000 |
Net Cash Paid (Received) for Income Taxes | -35,307,000 | -29,089,000 |
Noncash Acquisitions Under Capital Leases | 2,858,000 | 4,993,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 54,082,000 | 43,334,000 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of September 30, | 279,000 | 42,957,000 |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 19,000 | 28,057,000 |
Ohio Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 329,731,000 | 403,763,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 289,472,000 | 401,465,000 |
Deferred Income Taxes | 111,850,000 | 126,009,000 |
Asset Impairments and Other Related Charges | 154,304,000 | 0 |
Carrying Costs Income | -9,833,000 | -14,401,000 |
Allowance for Equity Funds Used During Construction | -2,853,000 | -3,036,000 |
Mark-to-Market of Risk Management Contracts | 14,037,000 | 12,420,000 |
Property Taxes | 166,607,000 | 164,496,000 |
Fuel Over/Under-Recovery, Net | 21,271,000 | 4,766,000 |
Deferral of Ohio Capacity Costs, Net | -156,952,000 | -21,541,000 |
Change in Other Noncurrent Assets | -29,012,000 | -55,769,000 |
Change in Other Noncurrent Liabilities | -11,664,000 | -11,019,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 123,893,000 | 29,255,000 |
Fuel, Materials and Supplies | 79,028,000 | -46,712,000 |
Accounts Payable | -67,487,000 | -135,419,000 |
Accrued Taxes, Net | -187,677,000 | -161,613,000 |
Other Current Assets | 3,246,000 | 2,599,000 |
Other Current Liabilities | -39,251,000 | -3,639,000 |
Net Cash Flows from (Used for) Operating Activities | 788,710,000 | 691,624,000 |
Investing Activities | ||
Construction Expenditures | -445,189,000 | -374,417,000 |
Change in Advances to Affiliates, Net | 101,616,000 | 94,852,000 |
Proceeds from Sales of Assets | 13,059,000 | 6,226,000 |
Other Investing Activities | -8,586,000 | 8,526,000 |
Net Cash Flows from (Used for) Investing Activities | -339,100,000 | -264,813,000 |
Financing Activities | ||
Issuance of Long-term Debt | 977,002,000 | 0 |
Issuance of Long-term Debt - Affiliated | 200,000,000 | 0 |
Change in Advances from Affiliates, Net | 1,063,000 | 0 |
Retirement of Long-term Debt | -1,146,000,000 | -194,500,000 |
Retirement of Long-term Debt - Affiliated | -200,000,000 | 0 |
Principal Payments for Capital Lease Obligations | -7,920,000 | -7,678,000 |
Dividends Paid on Common Stock | -275,000,000 | -225,000,000 |
Other Financing Activities | 1,946,000 | 202,000 |
Net Cash Flows from (Used for) Financing Activities | -448,909,000 | -426,976,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 701,000 | -165,000 |
Cash and Cash Equivalents at Beginning of Period | 3,640,000 | 2,095,000 |
Cash and Cash Equivalents at End of Period | 4,341,000 | 1,930,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 145,817,000 | 157,944,000 |
Net Cash Paid (Received) for Income Taxes | 38,446,000 | 33,400,000 |
Noncash Acquisitions Under Capital Leases | 5,756,000 | 5,658,000 |
Government Grants Included in Accounts Receivable as of September 30, | 377,000 | 585,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 68,481,000 | 56,357,000 |
Noncash Distribution of Cook Coal Terminal to Parent | -22,303,000 | 0 |
Public Service Co Of Oklahoma [Member] | ||
Operating Activities | ||
Net Income (Loss) | 93,221,000 | 105,962,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 72,449,000 | 71,356,000 |
Deferred Income Taxes | 39,665,000 | 22,524,000 |
Carrying Costs Income | -338,000 | -1,560,000 |
Allowance for Equity Funds Used During Construction | -2,676,000 | -1,298,000 |
Mark-to-Market of Risk Management Contracts | -4,984,000 | 3,868,000 |
Property Taxes | -10,177,000 | -9,673,000 |
Fuel Over/Under-Recovery, Net | -9,201,000 | 40,240,000 |
Change in Other Noncurrent Assets | -3,175,000 | 10,869,000 |
Change in Other Noncurrent Liabilities | -13,094,000 | -1,325,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 6,454,000 | 10,684,000 |
Fuel, Materials and Supplies | 3,876,000 | -2,320,000 |
Accounts Payable | 8,783,000 | -11,632,000 |
Accrued Taxes, Net | 37,739,000 | 43,313,000 |
Other Current Assets | 216,000 | -1,864,000 |
Other Current Liabilities | -3,780,000 | -1,275,000 |
Net Cash Flows from (Used for) Operating Activities | 214,978,000 | 277,869,000 |
Investing Activities | ||
Construction Expenditures | -172,602,000 | -151,603,000 |
Change in Advances to Affiliates, Net | -8,884,000 | -67,583,000 |
Other Investing Activities | 10,657,000 | 1,107,000 |
Net Cash Flows from (Used for) Investing Activities | -170,829,000 | -218,079,000 |
Financing Activities | ||
Issuance of Long-term Debt | 0 | 2,395,000 |
Retirement of Long-term Debt | -301,000 | -130,000 |
Principal Payments for Capital Lease Obligations | -2,558,000 | -2,585,000 |
Dividends Paid on Common Stock | -41,250,000 | -60,000,000 |
Other Financing Activities | 593,000 | 139,000 |
Net Cash Flows from (Used for) Financing Activities | -43,516,000 | -60,181,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 633,000 | -391,000 |
Cash and Cash Equivalents at Beginning of Period | 1,367,000 | 1,413,000 |
Cash and Cash Equivalents at End of Period | 2,000,000 | 1,022,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 36,054,000 | 36,681,000 |
Net Cash Paid (Received) for Income Taxes | 2,026,000 | 17,988,000 |
Noncash Acquisitions Under Capital Leases | 4,068,000 | 979,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | 33,820,000 | 23,872,000 |
Southwestern Electric Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 49,695,000 | 180,515,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 132,460,000 | 103,820,000 |
Deferred Income Taxes | 27,736,000 | 215,283,000 |
Asset Impairments and Other Related Charges | 110,850,000 | 13,000,000 |
Allowance for Equity Funds Used During Construction | -4,872,000 | -43,401,000 |
Mark-to-Market of Risk Management Contracts | -591,000 | -1,179,000 |
Property Taxes | -11,804,000 | -10,167,000 |
Fuel Over/Under-Recovery, Net | -24,110,000 | 10,429,000 |
Change in Other Noncurrent Assets | 21,935,000 | 12,522,000 |
Change in Other Noncurrent Liabilities | -10,203,000 | 25,945,000 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | -7,384,000 | -15,071,000 |
Fuel, Materials and Supplies | 8,638,000 | -27,911,000 |
Accounts Payable | -7,626,000 | -13,474,000 |
Accrued Taxes, Net | 36,127,000 | -24,649,000 |
Accrued Interest | -24,752,000 | -20,473,000 |
Other Current Assets | -1,483,000 | -7,940,000 |
Other Current Liabilities | -13,770,000 | -12,570,000 |
Net Cash Flows from (Used for) Operating Activities | 280,846,000 | 384,679,000 |
Investing Activities | ||
Construction Expenditures | -284,650,000 | -395,829,000 |
Change in Advances to Affiliates, Net | 135,195,000 | -128,227,000 |
Other Investing Activities | -383,000 | 1,240,000 |
Net Cash Flows from (Used for) Investing Activities | -149,838,000 | -522,816,000 |
Financing Activities | ||
Issuance of Long-term Debt | 0 | 336,429,000 |
Credit Facility Borrowings | 17,091,000 | 21,462,000 |
Change in Advances from Affiliates, Net | 0 | -132,473,000 |
Retirement of Long-term Debt | -3,250,000 | -21,625,000 |
Credit Facility Repayments | -19,694,000 | -38,478,000 |
Principal Payments for Capital Lease Obligations | -13,394,000 | -12,036,000 |
Dividends Paid on Common Stock | -93,750,000 | 0 |
Dividends Paid on Common Stock | -3,142,000 | -3,176,000 |
Other Financing Activities | 746,000 | 3,859,000 |
Net Cash Flows from (Used for) Financing Activities | -115,393,000 | 153,962,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 15,615,000 | 15,825,000 |
Cash and Cash Equivalents at Beginning of Period | 2,036,000 | 801,000 |
Cash and Cash Equivalents at End of Period | 17,651,000 | 16,626,000 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 115,627,000 | 74,656,000 |
Net Cash Paid (Received) for Income Taxes | 265,000 | -112,290,000 |
Noncash Acquisitions Under Capital Leases | 3,848,000 | 18,560,000 |
Construction Expenditures Included in Current Liabilities as of September 30, | $44,815,000 | $72,318,000 |
Significant_Accounting_Matters
Significant Accounting Matters | 9 Months Ended | ||||||||||||||
Sep. 30, 2013 | |||||||||||||||
Significant Accounting Matters | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | ||||||||||||||
CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS | |||||||||||||||
1. SIGNIFICANT ACCOUNTING MATTERS | |||||||||||||||
General | |||||||||||||||
The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2012 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2013. | |||||||||||||||
Earnings Per Share (EPS) | |||||||||||||||
Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. | |||||||||||||||
The following tables present our basic and diluted EPS calculations included on our condensed statements of income: | |||||||||||||||
Three Months Ended September 30, | |||||||||||||||
2013 | 2012 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 433 | $ | 487 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 486.9 | $ | 0.89 | 485 | $ | 1 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Stock Options | - | - | 0.1 | - | |||||||||||
Restricted Stock Units | 0.4 | - | 0.3 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 487.3 | $ | 0.89 | 485.4 | $ | 1 | |||||||||
Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 1,134 | $ | 1,238 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 486.4 | $ | 2.33 | 484.4 | $ | 2.55 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Stock Options | - | - | 0.1 | - | |||||||||||
Restricted Stock Units | 0.4 | - | 0.3 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 486.8 | $ | 2.33 | 484.8 | $ | 2.55 | |||||||||
There were no antidilutive shares outstanding as of September 30, 2013 and 2012. | |||||||||||||||
Appalachian Power Co [Member] | |||||||||||||||
Significant Accounting Matters | 1. SIGNIFICANT ACCOUNTING MATTERS | ||||||||||||||
General | |||||||||||||||
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||
Significant Accounting Matters | 1. SIGNIFICANT ACCOUNTING MATTERS | ||||||||||||||
General | |||||||||||||||
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |||||||||||||||
Ohio Power Co [Member] | |||||||||||||||
Significant Accounting Matters | 1. SIGNIFICANT ACCOUNTING MATTERS | ||||||||||||||
General | |||||||||||||||
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |||||||||||||||
Transfer of Cook Coal Terminal to AEGCo | |||||||||||||||
On August 1, 2013, OPCo transferred ownership of Cook Coal Terminal to AEGCo. Located in Metropolis, IL, Cook Coal Terminal performs coal transloading services for APCo and I&M and railcar maintenance services for APCo, I&M, PSO and SWEPCo. The transfer of Cook Coal Terminal resulted in a decrease in OPCo's total assets and total liabilities of $43.3 million and $40.6 million, respectively. | |||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||
Significant Accounting Matters | 1. SIGNIFICANT ACCOUNTING MATTERS | ||||||||||||||
General | |||||||||||||||
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||
Significant Accounting Matters | 1. SIGNIFICANT ACCOUNTING MATTERS | ||||||||||||||
General | |||||||||||||||
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |||||||||||||||
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. |
Comprehensive_Income
Comprehensive Income | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Securities | Pension | ||||||||||||||||||
Commodity | Foreign Currency | Available for Sale | and OPEB | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 1 | $ | -25 | $ | 5 | $ | -294 | $ | -313 | ||||||||||
Change in Fair Value Recognized in AOCI | 1 | - | 1 | - | 2 | |||||||||||||||
Amounts Reclassified from AOCI | -3 | 1 | - | 7 | 5 | |||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -2 | 1 | 1 | 7 | 7 | |||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -1 | $ | -24 | $ | 6 | $ | -287 | $ | -306 | ||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Securities | Pension | ||||||||||||||||||
Commodity | Foreign Currency | Available for Sale | and OPEB | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -8 | $ | -30 | $ | 4 | $ | -303 | $ | -337 | ||||||||||
Change in Fair Value Recognized in AOCI | 11 | 2 | 2 | - | 15 | |||||||||||||||
Amounts Reclassified from AOCI | -4 | 4 | - | 16 | 16 | |||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 7 | 6 | 2 | 16 | 31 | |||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -1 | $ | -24 | $ | 6 | $ | -287 | $ | -306 | ||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Utility Operations Revenues | $ | -1 | ||||||||||||||||||
Other Revenues | -3 | |||||||||||||||||||
Purchased Electricity for Resale | -1 | |||||||||||||||||||
Property, Plant and Equipment | - | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | - | |||||||||||||||||||
Subtotal - Commodity | -5 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 2 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -3 | |||||||||||||||||||
Income Tax (Expense) Credit | -1 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -2 | |||||||||||||||||||
Gains and Losses on Securities Available for Sale | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Interest Expense | - | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -7 | |||||||||||||||||||
Actuarial (Gains)/Losses | 18 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 11 | |||||||||||||||||||
Income Tax (Expense) Credit | 4 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 7 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 5 | ||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Utility Operations Revenues | $ | -1 | ||||||||||||||||||
Other Revenues | -8 | |||||||||||||||||||
Purchased Electricity for Resale | 3 | |||||||||||||||||||
Property, Plant and Equipment | - | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | - | |||||||||||||||||||
Subtotal - Commodity | -6 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 6 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 6 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Gains and Losses on Securities Available for Sale | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Interest Expense | - | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -16 | |||||||||||||||||||
Actuarial (Gains)/Losses | 41 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 25 | |||||||||||||||||||
Income Tax (Expense) Credit | 9 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 16 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 16 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Interest Rate | ||||||||||||||||||||
and Foreign | ||||||||||||||||||||
Commodity | Currency | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -14 | $ | -30 | $ | -44 | ||||||||||||||
Changes in Fair Value Recognized in AOCI | 16 | -3 | 13 | |||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI | ||||||||||||||||||||
to Statement of Income/within Balance Sheet: | ||||||||||||||||||||
Utility Operations Revenues | - | - | - | |||||||||||||||||
Other Revenues | -1 | - | -1 | |||||||||||||||||
Purchased Electricity for Resale | - | - | - | |||||||||||||||||
Interest Expense | - | 1 | 1 | |||||||||||||||||
Regulatory Assets (a) | - | - | - | |||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1 | $ | -32 | $ | -31 | ||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Interest Rate | ||||||||||||||||||||
and Foreign | ||||||||||||||||||||
Commodity | Currency | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -3 | $ | -20 | $ | -23 | ||||||||||||||
Changes in Fair Value Recognized in AOCI | -7 | -15 | -22 | |||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI | ||||||||||||||||||||
to Statement of Income/within Balance Sheet: | ||||||||||||||||||||
Utility Operations Revenues | - | - | - | |||||||||||||||||
Other Revenues | -4 | - | -4 | |||||||||||||||||
Purchased Electricity for Resale | 13 | - | 13 | |||||||||||||||||
Interest Expense | - | 3 | 3 | |||||||||||||||||
Regulatory Assets (a) | 2 | - | 2 | |||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1 | $ | -32 | $ | -31 | ||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
The following tables provide details of changes in unrealized gains and losses related to Securities Available for Sale and the reasons for changes for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 3 | ||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 1 | |||||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income: | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 4 | ||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 2 | ||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 2 | |||||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income: | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 4 | ||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
APCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 197 | $ | 2,583 | $ | -30,615 | $ | -27,835 | ||||||||||||
Change in Fair Value Recognized in AOCI | -47 | - | - | -47 | ||||||||||||||||
Amounts Reclassified from AOCI | -184 | 253 | 359 | 428 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -231 | 253 | 359 | 381 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -34 | $ | 2,836 | $ | -30,256 | $ | -27,454 | ||||||||||||
APCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -644 | $ | 2,077 | $ | -31,331 | $ | -29,898 | ||||||||||||
Change in Fair Value Recognized in AOCI | 684 | - | - | 684 | ||||||||||||||||
Amounts Reclassified from AOCI | -74 | 759 | 1,075 | 1,760 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 610 | 759 | 1,075 | 2,444 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -34 | $ | 2,836 | $ | -30,256 | $ | -27,454 | ||||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
APCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -75 | ||||||||||||||||||
Purchased Electricity for Resale | 21 | |||||||||||||||||||
Other Operation Expense | -14 | |||||||||||||||||||
Maintenance Expense | -11 | |||||||||||||||||||
Property, Plant and Equipment | -15 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -190 | |||||||||||||||||||
Subtotal - Commodity | -284 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 390 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 390 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 106 | |||||||||||||||||||
Income Tax (Expense) Credit | 37 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 69 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,282 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,834 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 552 | |||||||||||||||||||
Income Tax (Expense) Credit | 193 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 359 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 428 | ||||||||||||||||||
APCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -53 | ||||||||||||||||||
Purchased Electricity for Resale | 47 | |||||||||||||||||||
Other Operation Expense | -38 | |||||||||||||||||||
Maintenance Expense | -29 | |||||||||||||||||||
Property, Plant and Equipment | -34 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -9 | |||||||||||||||||||
Subtotal - Commodity | -116 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 1,169 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 1,169 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,053 | |||||||||||||||||||
Income Tax (Expense) Credit | 368 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 685 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -3,847 | |||||||||||||||||||
Actuarial (Gains)/Losses | 5,501 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,654 | |||||||||||||||||||
Income Tax (Expense) Credit | 579 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,075 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,760 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
I&M | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 147 | $ | -16,796 | $ | -8,439 | $ | -25,088 | ||||||||||||
Change in Fair Value Recognized in AOCI | -49 | - | - | -49 | ||||||||||||||||
Amounts Reclassified from AOCI | -117 | 410 | 174 | 467 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -166 | 410 | 174 | 418 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -19 | $ | -16,386 | $ | -8,265 | $ | -24,670 | ||||||||||||
I&M | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -446 | $ | -19,647 | $ | -8,790 | $ | -28,883 | ||||||||||||
Change in Fair Value Recognized in AOCI | 443 | 2,248 | - | 2,691 | ||||||||||||||||
Amounts Reclassified from AOCI | -16 | 1,013 | 525 | 1,522 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 427 | 3,261 | 525 | 4,213 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -19 | $ | -16,386 | $ | -8,265 | $ | -24,670 | ||||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
I&M | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -173 | ||||||||||||||||||
Purchased Electricity for Resale | 47 | |||||||||||||||||||
Other Operation Expense | -8 | |||||||||||||||||||
Maintenance Expense | -5 | |||||||||||||||||||
Property, Plant and Equipment | -10 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -31 | |||||||||||||||||||
Subtotal - Commodity | -180 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 631 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 631 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 451 | |||||||||||||||||||
Income Tax (Expense) Credit | 158 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 293 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -199 | |||||||||||||||||||
Actuarial (Gains)/Losses | 467 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 268 | |||||||||||||||||||
Income Tax (Expense) Credit | 94 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 174 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 467 | ||||||||||||||||||
I&M | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -89 | ||||||||||||||||||
Purchased Electricity for Resale | 115 | |||||||||||||||||||
Other Operation Expense | -23 | |||||||||||||||||||
Maintenance Expense | -14 | |||||||||||||||||||
Property, Plant and Equipment | -20 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | 7 | |||||||||||||||||||
Subtotal - Commodity | -24 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 1,558 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 1,558 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,534 | |||||||||||||||||||
Income Tax (Expense) Credit | 537 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 997 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -596 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,404 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 808 | |||||||||||||||||||
Income Tax (Expense) Credit | 283 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 525 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,522 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
OPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 289 | $ | 7,415 | $ | -166,369 | $ | -158,665 | ||||||||||||
Distribution of Cook Coal Terminal to Parent | - | - | 19,652 | 19,652 | ||||||||||||||||
Change in Fair Value Recognized in AOCI | -86 | - | - | -86 | ||||||||||||||||
Amounts Reclassified from AOCI | -250 | -339 | 2,985 | 2,396 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -336 | -339 | 2,985 | 2,310 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -47 | $ | 7,076 | $ | -143,732 | $ | -136,703 | ||||||||||||
OPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -912 | $ | 8,095 | $ | -172,908 | $ | -165,725 | ||||||||||||
Distribution of Cook Coal Terminal to Parent | - | - | 19,652 | 19,652 | ||||||||||||||||
Change in Fair Value Recognized in AOCI | 907 | - | - | 907 | ||||||||||||||||
Amounts Reclassified from AOCI | -42 | -1,019 | 9,524 | 8,463 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 865 | -1,019 | 9,524 | 9,370 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -47 | $ | 7,076 | $ | -143,732 | $ | -136,703 | ||||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
OPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -461 | ||||||||||||||||||
Purchased Electricity for Resale | 129 | |||||||||||||||||||
Other Operation Expense | -20 | |||||||||||||||||||
Maintenance Expense | -11 | |||||||||||||||||||
Property, Plant and Equipment | -21 | |||||||||||||||||||
Subtotal - Commodity | -384 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Depreciation and Amortization Expense | 2 | |||||||||||||||||||
Interest Expense | -524 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -522 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -906 | |||||||||||||||||||
Income Tax (Expense) Credit | -317 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -589 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,451 | |||||||||||||||||||
Actuarial (Gains)/Losses | 6,044 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 4,593 | |||||||||||||||||||
Income Tax (Expense) Credit | 1,608 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 2,985 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 2,396 | ||||||||||||||||||
OPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -246 | ||||||||||||||||||
Purchased Electricity for Resale | 309 | |||||||||||||||||||
Other Operation Expense | -57 | |||||||||||||||||||
Maintenance Expense | -26 | |||||||||||||||||||
Property, Plant and Equipment | -44 | |||||||||||||||||||
Subtotal - Commodity | -64 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Depreciation and Amortization Expense | 5 | |||||||||||||||||||
Interest Expense | -1,573 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -1,568 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -1,632 | |||||||||||||||||||
Income Tax (Expense) Credit | -571 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,061 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -4,388 | |||||||||||||||||||
Actuarial (Gains)/Losses | 19,040 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 14,652 | |||||||||||||||||||
Income Tax (Expense) Credit | 5,128 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 9,524 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 8,463 | ||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
PSO | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | ||||||||||||||||||||
Commodity | Foreign Currency | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | -21 | $ | 6,081 | $ | 6,060 | ||||||||||||||
Change in Fair Value Recognized in AOCI | 32 | - | 32 | |||||||||||||||||
Amounts Reclassified from AOCI | -14 | -190 | -204 | |||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 18 | -190 | -172 | |||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | 5,891 | $ | 5,888 | ||||||||||||||
PSO | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | ||||||||||||||||||||
Commodity | Foreign Currency | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | 21 | $ | 6,460 | $ | 6,481 | ||||||||||||||
Change in Fair Value Recognized in AOCI | 7 | 1 | 8 | |||||||||||||||||
Amounts Reclassified from AOCI | -31 | -570 | -601 | |||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -24 | -569 | -593 | |||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | 5,891 | $ | 5,888 | ||||||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
PSO | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -10 | ||||||||||||||||||
Maintenance Expense | -5 | |||||||||||||||||||
Property, Plant and Equipment | -7 | |||||||||||||||||||
Subtotal - Commodity | -22 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | -292 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -292 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -314 | |||||||||||||||||||
Income Tax (Expense) Credit | -110 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -204 | ||||||||||||||||||
PSO | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -25 | ||||||||||||||||||
Maintenance Expense | -9 | |||||||||||||||||||
Property, Plant and Equipment | -14 | |||||||||||||||||||
Subtotal - Commodity | -48 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | -876 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -876 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -924 | |||||||||||||||||||
Income Tax (Expense) Credit | -323 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -601 | ||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Comprehensive Income | 2. COMPREHENSIVE INCOME | |||||||||||||||||||
Presentation of Comprehensive Income | ||||||||||||||||||||
The following tables provide the components of changes in AOCI for the three and nine months ended September 30, 2013. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
SWEPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | -26 | $ | -14,437 | $ | -2,438 | $ | -16,901 | ||||||||||||
Change in Fair Value Recognized in AOCI | 40 | - | - | 40 | ||||||||||||||||
Amounts Reclassified from AOCI | -17 | 566 | -64 | 485 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 23 | 566 | -64 | 525 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | -13,871 | $ | -2,502 | $ | -16,376 | ||||||||||||
SWEPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | 22 | $ | -15,571 | $ | -2,311 | $ | -17,860 | ||||||||||||
Change in Fair Value Recognized in AOCI | 13 | - | - | 13 | ||||||||||||||||
Amounts Reclassified from AOCI | -38 | 1,700 | -191 | 1,471 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -25 | 1,700 | -191 | 1,484 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | -13,871 | $ | -2,502 | $ | -16,376 | ||||||||||||
Reclassifications Out of Accumulated Other Comprehensive Income | ||||||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three and nine months ended September 30, 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. | ||||||||||||||||||||
SWEPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -12 | ||||||||||||||||||
Maintenance Expense | -7 | |||||||||||||||||||
Property, Plant and Equipment | -8 | |||||||||||||||||||
Subtotal - Commodity | -27 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 872 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 872 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 845 | |||||||||||||||||||
Income Tax (Expense) Credit | 296 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 549 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -446 | |||||||||||||||||||
Actuarial (Gains)/Losses | 348 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -98 | |||||||||||||||||||
Income Tax (Expense) Credit | -34 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -64 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 485 | ||||||||||||||||||
SWEPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -28 | ||||||||||||||||||
Maintenance Expense | -14 | |||||||||||||||||||
Property, Plant and Equipment | -16 | |||||||||||||||||||
Subtotal - Commodity | -58 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 2,616 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2,616 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,558 | |||||||||||||||||||
Income Tax (Expense) Credit | 896 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,662 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,338 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,044 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -294 | |||||||||||||||||||
Income Tax (Expense) Credit | -103 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -191 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,471 | ||||||||||||||||||
The following tables provide details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2012. All amounts in the following tables are presented net of related income taxes. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate_Matters
Rate Matters | 9 Months Ended | |||||||||
Sep. 30, 2013 | ||||||||||
Rate Matters | 3. RATE MATTERS | |||||||||
As discussed in the 2012 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
(in millions) | ||||||||||
Noncurrent Regulatory Assets | ||||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Storm Related Costs | $ | 22 | $ | 23 | ||||||
Economic Development Rider | 14 | 13 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 3 | 1 | ||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 153 | 172 | ||||||||
Ormet Special Rate Recovery Mechanism | 32 | 5 | ||||||||
Virginia Environmental Rate Adjustment Clause | 28 | 29 | ||||||||
Expanded Net Energy Charge - Coal Inventory | 21 | - | ||||||||
Under-Recovered Capacity Costs | 16 | - | ||||||||
Mountaineer Carbon Capture and Storage Product Validation Facility | 14 | 14 | ||||||||
Litigation Settlement | - | 11 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 38 | 36 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 341 | $ | 304 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
OPCo Rate Matters | ||||||||||
Ohio Electric Security Plan Filing | ||||||||||
2009 – 2011 ESP | ||||||||||
The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO. | ||||||||||
In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of September 30, 2013, OPCo's net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. | ||||||||||
In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011. The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013. In September 2013, a proposed second phase of OPCo's gridSMART program was filed with the PUCO which included a recommended technology solution project to satisfy this PUCO directive. | ||||||||||
In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. In October 2013, the PUCO issued an order on the 2010 SEET filing. As a result, the PUCO ordered a $7 million refund of pretax earnings to customers. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. The PUCO approved OPCo's requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. | ||||||||||
In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. The IEU and the Ohio Consumers' Counsel also filed appeals, regarding the PUCO decision in the PIRR proceeding, at the Supreme Court of Ohio in November 2012 arguing principally that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenor appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of September 30, 2013, could reduce carrying costs by $33 million including $17 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. | ||||||||||
Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
June 2012 – May 2015 ESP Including Capacity Charge | ||||||||||
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013. | ||||||||||
As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of final orders in both the ESP and corporate separation cases and extending through May 2015. The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. | ||||||||||
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As of September 30, 2013, OPCo's incurred deferred capacity costs balance of $228 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. | ||||||||||
As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. | ||||||||||
In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR. | ||||||||||
In June 2013, intervenors in the CBP docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo's non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo's non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013. A decision from the PUCO is pending. | ||||||||||
If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Corporate Separation | ||||||||||
In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC. | ||||||||||
Also in October 2012, filings at the FERC were submitted related to corporate separation. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo. Results of operations related to generation in Ohio will be largely determined by prevailing market conditions effective January 1, 2014. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. | ||||||||||
Storm Damage Recovery Rider (SDRR) | ||||||||||
In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. OPCo also requested approval of a weighted average cost of capital carrying charge if recovery of these costs did not begin prior to April 2013. In May 2013, intervenors filed comments with various recommendations including reductions in the amount of storm costs recoverable up to the amount deferred, an extended recovery period, and an additional review of the storm costs including the allocation of costs to capital. Hearings at the PUCO are scheduled for December 2013. As of September 30, 2013, OPCo recorded $61 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2009 Fuel Adjustment Clause Audit | ||||||||||
The PUCO selected an outside consultant to conduct an audit of OPCo's FAC for 2009. The outside consultant provided its audit report to the PUCO. In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2010 and 2011 Fuel Adjustment Clause Audits | ||||||||||
The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO are scheduled for November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. | ||||||||||
Ormet | ||||||||||
Ormet, a large aluminum company, has a contract through 2018 to purchase power from OPCo. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, following applications to the PUCO to amend Ormet's power contract with OPCo, Ormet announced that they are unable to emerge from bankruptcy and are shutting down operations effective immediately. Based upon previous PUCO rulings to provide rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider. As of September 30, 2013, OPCo has recorded a regulatory asset of $32 million of Ormet amounts collectible through the Economic Development Rider as a result of these special rate recovery mechanisms and amounts unpaid by Ormet. | ||||||||||
In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised the issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. | ||||||||||
To the extent amounts referenced above are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Ohio IGCC Plant | ||||||||||
In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of September 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. | ||||||||||
Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
SWEPCo Rate Matters | ||||||||||
Turk Plant | ||||||||||
SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of September 30, 2013, SWEPCo's share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million. As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion. | ||||||||||
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. | ||||||||||
The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap. SWEPCo appealed the PUCT's order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT's grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT's order in all respects. In March 2013, SWEPCo and the TIEC's petitions for review at the Supreme Court of Texas were denied and in August 2013, SWEPCo and the TIEC's motions for rehearing at the Supreme Court of Texas were denied. | ||||||||||
If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2012 Texas Base Rate Case | ||||||||||
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs. | ||||||||||
In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo's existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates. In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010. | ||||||||||
The PUCT rejected the ALJ's imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal discussed above (the Texas capital cost cap). The PUCT also provided new details on how the cost cap would be applied. In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo's recovery of AFUDC in addition to its recovery of cash construction costs. As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income. The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%. As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013. The approval also provided for the following: (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year. Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2013, the net book value of Welsh Plant, Unit 2 was $94 million, before cost of removal, including materials and supplies inventory and CWIP. Requests for rehearing may be filed within 30 days of receipt of the PUCT order. SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013. | ||||||||||
If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2012 Louisiana Formula Rate Filing | ||||||||||
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Flint Creek Plant Environmental Controls | ||||||||||
In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. | ||||||||||
APCo and WPCo Rate Matters | ||||||||||
Plant Transfers | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity presently owned by OPCo. In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo's proposed asset transfers including the transfer of only one plant and the issuance of a Request for Proposals for any additional capacity and energy requirements. Also in June 2013, the WVPSC staff filed testimony recommending the approval of the proposed asset transfers, with rate recognition to occur in a future base rate case, but limiting the liabilities to be transferred to the types and amounts reflected in the net book value of the assets. In July 2013, the Virginia SCC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the disallowance is approximately $39 million. The Virginia SCC also denied the proposed transfer of OPCo's one-half interest in the Mitchell Plant to APCo. APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing. Management is currently evaluating the implications of this order while awaiting a final decision from the WVPSC. Hearings were held at the WVPSC in July 2013. In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo at the reduced value, for rate purposes, as approved by the Virginia SCC which could result in an additional $44 million disallowance related to the West Virginia and FERC jurisdictional shares of Amos Plant, Unit 3 and the denial of the proposed transfer of OPCo's one-half interest in the Mitchell Plant to APCo. This matter is currently pending before the WVPSC. Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013. If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
APCo IGCC Plant | ||||||||||
As of September 30, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing | ||||||||||
In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs. In September 2013, the Hearing Examiner recommended the approval of the settlement agreement. An order is expected from the Virginia SCC no later than November 2013. APCo has deferred $28 million as of September 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs. If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows. | ||||||||||
2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing | ||||||||||
In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant. In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an increase in the generation RAC to $37 million annually if the proposed merger of WPCo into APCo occurs by January 1, 2014 or an increase to $39 million if the proposed merger does not occur by January 1, 2014. Per the settlement agreement, the generation RAC increase is to be effective no later than March 2014 for a period of one year at which time the component to collect an under-recovery of approximately $9 million will cease and the remaining component to recover on-going Dresden Plant costs will continue. In October 2013, the Hearing Examiner recommended the approval of the settlement agreement. An order is expected from the Virginia SCC no later than December 2013. APCo has deferred $6 million as of September 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs. If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows. | ||||||||||
2013 West Virginia Expanded Net Energy Charge (ENEC) Filing | ||||||||||
In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million. Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period. In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs. In September 2013, the WVPSC approved the settlement agreement. The securitization bonds are expected to be issued in the fourth quarter of 2013. | ||||||||||
In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement. The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs. In August 2013, the WVPSC approved a settlement that includes (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. | ||||||||||
As of September 30, 2013, APCo's ENEC under-recovery balance of $281 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $2 million of unrecognized equity carrying costs and $14 million of other ENEC-related assets. | ||||||||||
Virginia Storm Costs | ||||||||||
In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. The estimated 2013 earnings component will be reviewed quarterly to determine if any storm costs can be deferred. As of September 30, 2013, there were no deferrals of Virginia storm costs incurred in 2012 or 2013. If this quarterly test allows APCo to defer previously expensed storm costs for future recovery, it could increase future net income and cash flows. | ||||||||||
PSO Rate Matters | ||||||||||
Oklahoma Environmental Compliance Plan | ||||||||||
In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026. As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP. In August 2013, the OCC dismissed PSO's environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding. PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan. If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
I&M Rate Matters | ||||||||||
2011 Indiana Base Rate Case | ||||||||||
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. | ||||||||||
Cook Plant Life Cycle Management Project (LCM Project) | ||||||||||
In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC. | ||||||||||
In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates. In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014. | ||||||||||
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. | ||||||||||
If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Rockport Plant Clean Coal Technology Project (CCT Project) | ||||||||||
In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system. The estimated cost in the application was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. | ||||||||||
In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. If the IURC approves the settlement agreement, I&M's Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. A hearing was held at the IURC in August 2013 and a decision is expected by November 2013. As of September 30, 2013, we have incurred costs of $93 million related to the CCT Project, including AFUDC. If we are not ultimately permitted to recover our incurred costs, it could reduce future net income and cash flows. | ||||||||||
Tanners Creek Plant, Units 1 - 4 | ||||||||||
In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering the net book value of Tanners Creek Plant, Units 1-4 in base rates, and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases. As of September 30, 2013, the combined net book value of Tanners Creek Plant, Units 1-4 was $342 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of Tanners Creek Plant, Units 1-4, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
KPCo Rate Matters | ||||||||||
Plant Transfer | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by OPCo. KPCo also requested costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of September 30, 2013, the net book value of Big Sandy, Unit 2 was $251 million, before cost of removal, including materials and supplies inventory and CWIP. KPCo is currently seeking recovery of these costs with the KPSC. In March 2013, KPCo issued a Request for Proposal (RFP) to purchase up to 250 MW of long-term capacity and energy to replace a portion of the capacity from the retirement of Big Sandy Plant, Unit 1. In June 2013, KPCo filed the results of its RFP with the KPSC. | ||||||||||
In July 2013, KPCo, Kentucky Industrial Utility Customers, Inc. (KIUC) and the Sierra Club filed a settlement agreement with the KPSC. The settlement included the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up. The settlement also allows KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement included the authorization to record FGD project costs as a regulatory asset, the conversion of Big Sandy Plant, Unit 1 to natural gas and addressed potential greenhouse gas initiatives on the Mitchell Plant. In October 2013, the KPSC issued an order approving a modified settlement agreement that included a limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order, which is currently pending. Additionally, the order rejected KPCo's request to defer FGD project costs for Big Sandy, Unit 2. Also in October 2013, KPCo filed with the KPSC accepting and agreeing to be bound by the modifications to the settlement agreement. As a result of this order, in the third quarter of 2013, KPCo recorded a pretax impairment of $33 million in Asset Impairments and Other Related Charges on the statement of income. | ||||||||||
2013 Kentucky Base Rate Case | ||||||||||
In June 2013, KPCo filed a request with the KPSC for an annual increase in base rates of $114 million based upon a return on common equity of 10.65% to be effective January 2014. The proposed revenue increase includes cost recovery of the pending transfer of the one-half interest in the Mitchell Plant (780 MW). In October 2013, the KPSC issued an order which modified and approved a settlement agreement relating to the proposed transfer of the one-half interest in the Mitchell Plant, in which KPCo agreed to withdraw this base rate case request. KPCo intends to withdraw this base rate request following the resolution of any potential requests for rehearing or appeals of the KPSC order. Assuming KPCo withdraws the base rate case, current base rates will remain in effect until at least May 2015. | ||||||||||
FERC Rate Matters | ||||||||||
Corporate Separation and Termination of Interconnection Agreement | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo's current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo's Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the KPSC, the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters. | ||||||||||
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo, I&M and KPCo would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo, I&M and KPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC. | ||||||||||
Additionally, FERC approval was sought for a power supply agreement between AEPGenCo and OPCo. This agreement provides for AEPGenCo to supply capacity for OPCo's switched and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo's non-switched retail load that is not acquired through an auction from January 1, 2014 through December 31, 2014. | ||||||||||
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. See the “Plant Transfers” section of APCo and WPCo Rate Matters and the “Plant Transfer” section of KPCo Rate Matters for a discussion of those orders. | ||||||||||
If corporate separation is approved as filed, for any AEPGenCo generation not serving OPCo's retail load, AEPGenCo's results of operations will be largely determined by prevailing market conditions effective January 1, 2014. If incurred costs are not ultimately recovered, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Appalachian Power Co [Member] | ||||||||||
Rate Matters | Plant Transfers | |||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC regarding the transfer of certain generation plants within the AEP System. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. In December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant, comprising 1,647 MW of generating capacity presently owned by OPCo. In June 2013, intervenors filed testimony with the WVPSC and made recommendations relating to APCo's proposed asset transfers including the transfer of only one plant and the issuance of a Request for Proposals for any additional capacity and energy requirements. Also in June 2013, the WVPSC staff filed testimony recommending the approval of the proposed asset transfers, with rate recognition to occur in a future base rate case, but limiting the liabilities to be transferred to the types and amounts reflected in the net book value of the assets. In July 2013, the Virginia SCC approved the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but, for rate purposes, reduced the proposed transfer price by $83 million pretax. The Virginia jurisdictional share of the disallowance is approximately $39 million. The Virginia SCC also denied the proposed transfer of OPCo's one-half interest in the Mitchell Plant to APCo. APCo plans to pursue cost recovery of the transferred interest in the Amos Plant in Virginia in the 2014 biennial filing. Management is currently evaluating the implications of this order while awaiting a final decision from the WVPSC. Hearings were held at the WVPSC in July 2013. In September 2013, a WVPSC staff brief advocated for the approval of the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo at the reduced value, for rate purposes, as approved by the Virginia SCC which could result in an additional $44 million disallowance related to the West Virginia and FERC jurisdictional shares of Amos Plant, Unit 3 and the denial of the proposed transfer of OPCo's one-half interest in the Mitchell Plant to APCo. This matter is currently pending before the WVPSC. Any disallowance related to recovery of Amos Plant, Unit 3, as a result of Virginia SCC or WVPSC orders, would be recorded upon the transfer, expected in the fourth quarter of 2013. If APCo and WPCo are not ultimately permitted to recover their incurred costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
APCo IGCC Plant | ||||||||||
As of September 30, 2013, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction. If the costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Virginia Environmental Rate Adjustment Clause (Environmental RAC) Filing | ||||||||||
In March 2013, APCo filed with the Virginia SCC for approval of an environmental RAC to recover $39 million related to 2012 and 2011 environmental compliance costs effective February 2014 over a one-year period. In March 2013, the environmental RAC surcharge expired related to the collection of 2009 and 2010 environmental compliance costs. In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an environmental RAC to recover $38 million of the 2012 and 2011 environmental compliance costs. In September 2013, the Hearing Examiner recommended the approval of the settlement agreement. An order is expected from the Virginia SCC no later than November 2013. APCo has deferred $28 million as of September 30, 2013 for the Virginia portion of unrecovered environmental RAC costs incurred in 2012 and 2011, excluding $10 million of unrecognized equity carrying costs. If the Virginia SCC were to disallow any portion of the environmental RAC, it could reduce future net income and cash flows. | ||||||||||
2013 Virginia Generation Rate Adjustment Clause (Generation RAC) Filing | ||||||||||
In March 2013, APCo filed with the Virginia SCC for an increase in its generation RAC revenues of $12 million for a total of $38 million annually to collect costs related to the Dresden Plant. In August 2013, a settlement agreement was submitted to the Virginia SCC which recommended approval of an increase in the generation RAC to $37 million annually if the proposed merger of WPCo into APCo occurs by January 1, 2014 or an increase to $39 million if the proposed merger does not occur by January 1, 2014. Per the settlement agreement, the generation RAC increase is to be effective no later than March 2014 for a period of one year at which time the component to collect an under-recovery of approximately $9 million will cease and the remaining component to recover on-going Dresden Plant costs will continue. In October 2013, the Hearing Examiner recommended the approval of the settlement agreement. An order is expected from the Virginia SCC no later than December 2013. APCo has deferred $6 million as of September 30, 2013 for the Virginia portion of unrecovered costs of the Dresden Plant, excluding $4 million of unrecognized equity carrying costs. If the Virginia SCC were to disallow any portion of the generation RAC, it could reduce future net income and cash flows. | ||||||||||
2013 West Virginia Expanded Net Energy Charge (ENEC) Filing | ||||||||||
In March 2012, West Virginia passed securitization legislation which allows the WVPSC to establish a regulatory framework for electric utilities to securitize certain deferred ENEC balances and other ENEC-related assets. In August 2012, APCo and WPCo filed a request with the WVPSC for a financing order to securitize a total of $422 million related to the December 2011 under-recovered ENEC deferral balance including other ENEC-related assets of $13 million and related future financing costs of $7 million. Upon completion of the securitization, APCo would offset its current ENEC rates by an amount to recover the securitized balance over the securitization period. In March 2013, APCo, WPCo and intervenors filed a settlement agreement with the WVPSC which recommended the WVPSC authorize APCo to securitize $376 million plus upfront financing costs. In September 2013, the WVPSC approved the settlement agreement. The securitization bonds are expected to be issued in the fourth quarter of 2013. | ||||||||||
In April 2013, APCo and WPCo filed to keep total rates unchanged with a portion of the ENEC to be specifically identified for the amount to be securitized in accordance with the proposed securitization settlement agreement. The remaining ENEC rate is proposed to include (a) the proposed transfer of certain generation facilities from OPCo and the APCo/WPCo merger, (b) construction surcharges and (c) ongoing ENEC costs. In August 2013, the WVPSC approved a settlement that includes (a) a $56 million reduction in ENEC revenues, offset by a $6 million annual increase in construction surcharges, effective September 2013 and subject to true-up, (b) an agreement to file a base case no later than June 2014 and (c) the deferral of $21 million from the ENEC recovery balance with the ability to include that amount in the ENEC recovery balance upon reaching certain coal inventory levels at the Amos Plant. | ||||||||||
As of September 30, 2013, APCo's ENEC under-recovery balance of $281 million, net of 2012 and 2013 over-recovery, was recorded in Regulatory Assets on the balance sheet, excluding $2 million of unrecognized equity carrying costs and $14 million of other ENEC-related assets. | ||||||||||
Virginia Storm Costs | ||||||||||
In March 2013, due to the 2013 enactment of a Virginia law, APCo wrote off $30 million of previously deferred 2012 Virginia storm costs. The change in law affected the test years to be included in APCo's next biennial Virginia base rate filing in March 2014 and the determination of how these costs are treated in the Virginia jurisdictional biennial earnings test for 2012 and 2013. The estimated 2013 earnings component will be reviewed quarterly to determine if any storm costs can be deferred. As of September 30, 2013, there were no deferrals of Virginia storm costs incurred in 2012 or 2013. If this quarterly test allows APCo to defer previously expensed storm costs for future recovery, it could increase future net income and cash flows. | ||||||||||
3. RATE MATTERS | ||||||||||
As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
APCo | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 65,206 | $ | 94,458 | ||||||
Virginia Environmental Rate Adjustment Clause | 28,417 | 29,320 | ||||||||
Expanded Net Energy Charge - Coal Inventory | 20,528 | - | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Product Validation Facility | 14,155 | 14,155 | ||||||||
Dresden Plant Operating Costs | 8,358 | 8,758 | ||||||||
Transmission Agreement Phase-In | 3,313 | 2,992 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,287 | 1,287 | ||||||||
Deferred Wind Power Costs | - | 5,143 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 4,246 | 1,447 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 145,510 | $ | 157,560 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
APCo Rate Matters | ||||||||||
WPCo Merger with APCo | ||||||||||
In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC and in April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval of the transfers at net book value to APCo of OPCo's two-thirds interest in Amos Plant, Unit 3 and OPCo's one-half interest in the Mitchell Plant. In June 2013, the WVPSC issued an order consolidating the merger case with APCo's plant asset transfer case. Also in June 2013, WVPSC staff filed testimony that included a recommendation that the WVPSC approve the proposed merger. Hearings were held at the WVPSC in July 2013. These matters are pending before the WVPSC. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of OPCo's two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of OPCo's one-half interest in the Mitchell Plant to APCo. Although the Virginia SCC authorized the merger of WPCo into APCo, denial of the Mitchell Plant ownership transfer means there will be insufficient generation to serve the merged company. Management intends to review the feasibility of the merger once the WVPSC issues an order in the consolidated cases. See the “Plant Transfers” section of APCo Rate Matters and the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. | ||||||||||
FERC Rate Matters | ||||||||||
Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo's current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo's Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo Rate Matters. | ||||||||||
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC. | ||||||||||
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. | ||||||||||
If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows. | ||||||||||
Indiana Michigan Power Co [Member] | ||||||||||
Rate Matters | I&M Rate Matters | |||||||||
2011 Indiana Base Rate Case | ||||||||||
In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2%. In a March 2013 order, the IURC approved an adjustment which increased the authorized annual increase in base rates from $85 million to $92 million. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed a request for reconsideration with the IURC, which was denied. Also in March 2013, the OUCC filed an appeal of the order with the Indiana Court of Appeals. In September 2013, the OUCC filed a brief on appeal that included objections to the inclusion of a prepaid pension asset in rate base, the use of an end-of-test-year amount for materials and supplies instead of a thirteen-month average and the application of an “outdated” capital structure. If the order is overturned by the Indiana Court of Appeals, it could reduce future net income and cash flows. | ||||||||||
Cook Plant Life Cycle Management Project (LCM Project) | ||||||||||
In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its extended licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of September 30, 2013, I&M has incurred $285 million related to the LCM Project, including AFUDC. | ||||||||||
In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery in a base rate case. I&M was granted recovery through an LCM rider which will be determined by a proceeding in the fourth quarter of 2013 and semi-annual proceedings thereafter. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in its rates. In October 2013, I&M filed an application with the IURC for LCM rider rates to be effective January 2014. | ||||||||||
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to certain projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project. | ||||||||||
If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Tanners Creek Plant, Units 1 - 4 | ||||||||||
In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering the net book value of Tanners Creek Plant, Units 1-4 in base rates, and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases. As of September 30, 2013, the combined net book value of Tanners Creek Plant, Units 1-4 was $342 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of Tanners Creek Plant, Units 1-4, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
3. RATE MATTERS | ||||||||||
As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
I&M | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Under-Recovered Capacity Costs | $ | 16,445 | $ | - | ||||||
Indiana Deferred Cook Plant Life Cycle Management Project Costs | 3,198 | - | ||||||||
Litigation Settlement | - | 11,098 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | - | 1,380 | ||||||||
Other Regulatory Asset Not Yet Being Recovered | 3,316 | 786 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 22,959 | $ | 13,264 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Rockport Plant Clean Coal Technology Project (CCT Project) | ||||||||||
In April 2013, I&M filed an application with the IURC seeking approval of a Certificate of Public Convenience and Necessity (CPCN) to retrofit both units of the Rockport Plant with a Dry Sorbent Injection system. The estimated cost of the CCT Project was $285 million, excluding AFUDC to be shared equally between I&M and AEGCo. The application requested deferral treatment of any unrecovered carrying costs incurred during construction and incremental post in-service depreciation expense and operation and maintenance expenses until such costs are recognized and recovered in a rider. I&M also requested cost recovery associated with the retrofit using the Clean Coal Technology Rider recovery mechanism. | ||||||||||
In July 2013, a settlement agreement was filed with the IURC. The settlement agreement includes the approval of the CPCN with an updated estimated CCT Project cost of $258 million, excluding AFUDC, and the recovery of the Indiana jurisdictional share of I&M's ownership share of $129 million. The settlement agreement specifies that 80% of the recoverable I&M direct ownership share of CCT Project costs will be recovered through a Federal Mandate Rider with the remaining 20% deferred until rates are established in a subsequent rate case. If the IURC approves the settlement agreement, I&M's Indiana allocated share of the CCT Project costs received in the form of purchased power from AEGCo will be recovered in subsequent I&M rate cases. A hearing was held at the IURC in August 2013 and a decision is expected by November 2013. As of September 30, 2013, I&M has incurred costs of $48 million related to the CCT Project, including AFUDC. If I&M is not ultimately permitted to recover its incurred costs, it could reduce future net income and cash flows. | ||||||||||
FERC Rate Matters | ||||||||||
Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo's current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo's Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo Rate Matters. | ||||||||||
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC. | ||||||||||
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. | ||||||||||
If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows. | ||||||||||
Ohio Power Co [Member] | ||||||||||
Rate Matters | OPCo Rate Matters | |||||||||
Ohio Electric Security Plan Filing | ||||||||||
2009 – 2011 ESP | ||||||||||
The PUCO issued an order in March 2009 that modified and approved the ESP which established rates at the start of the April 2009 billing cycle through 2011. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO. | ||||||||||
In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of September 30, 2013, OPCo's net deferred fuel balance was $467 million, excluding unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. | ||||||||||
In January 2011, the PUCO issued an order on the 2009 SEET filing, which resulted in a write-off in 2010 and a subsequent refund to customers during 2011. The 2009 SEET order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project by the end of 2013. In September 2013, a proposed second phase of OPCo's gridSMART program was filed with the PUCO which included a recommended technology solution project to satisfy this PUCO directive. | ||||||||||
In July 2011, OPCo filed its 2010 SEET filing with the PUCO based upon the approach in the PUCO's 2009 order. In October 2013, the PUCO issued an order on the 2010 SEET filing. As a result, the PUCO ordered a $7 million refund of pretax earnings to customers. OPCo is required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. The PUCO approved OPCo's requests to file the SEET for 2011 and 2012 one month after the PUCO issues an order on the 2010 SEET. Management does not currently believe that there were significantly excessive earnings in 2011 for either CSPCo or OPCo or in 2012 for OPCo. Additionally, management does not currently believe that there will be significantly excessive earnings in 2013 for OPCo. | ||||||||||
In August 2012, the PUCO issued an order in a separate proceeding which implemented a Phase-In Recovery Rider (PIRR) to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. The IEU and the Ohio Consumers' Counsel also filed appeals, regarding the PUCO decision in the PIRR proceeding, at the Supreme Court of Ohio in November 2012 arguing principally that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenor appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of September 30, 2013, could reduce carrying costs by $33 million including $17 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending. | ||||||||||
Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
June 2012 – May 2015 ESP Including Capacity Charge | ||||||||||
In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015, which was generally upheld in rehearing orders in January and March 2013. | ||||||||||
As part of the ESP decision, the PUCO ordered OPCo to conduct an energy-only auction for 10% of the SSO load with delivery beginning six months after the receipt of final orders in both the ESP and corporate separation cases and extending through May 2015. The initiation of the auction is pending the issuance of an order by the PUCO in a separate docket. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning June 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. | ||||||||||
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the Reliability Pricing Model (RPM) price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The RPM price is approximately $33/MW day through May 2014. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As of September 30, 2013, OPCo's incurred deferred capacity costs balance of $228 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. | ||||||||||
As part of the August 2012 ESP order, the PUCO established a non-bypassable Retail Stability Rider (RSR), effective September 2012. The RSR will be collected from customers at $3.50/MWh through May 2014 and $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. | ||||||||||
In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR. | ||||||||||
In June 2013, intervenors in the CBP docket filed recommendations that include prospective rate reductions for capacity and non-energy FAC issues. OPCo maintains that the August 2012 ESP order fixed OPCo's non-energy generation rates through December 31, 2014 and ordered the application of a $188.88/MW day price for capacity for non-shopping customers effective January 1, 2015. However, intervenors maintained that OPCo's non-energy generation rates should be reduced prior to January 1, 2015 to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned (10% prior to June 2014 and 60% for the period June 1, 2014 through December 31, 2014). An additional proposal to prospectively offset deferred capacity costs based upon the results of the energy-only auctions was not quantified and OPCo maintains that proposal should not be adopted in light of prior PUCO orders. Hearings related to the CBP were held at the PUCO in June and July 2013. A decision from the PUCO is pending. | ||||||||||
If OPCo is ultimately not permitted to fully collect its ESP rates including the RSR, and its deferred capacity costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Storm Damage Recovery Rider (SDRR) | ||||||||||
In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates. The SDRR seeks recovery of 2012 incremental storm distribution expenses over twelve months starting with the effective date of the SDRR as approved by the PUCO. OPCo also requested approval of a weighted average cost of capital carrying charge if recovery of these costs did not begin prior to April 2013. In May 2013, intervenors filed comments with various recommendations including reductions in the amount of storm costs recoverable up to the amount deferred, an extended recovery period, and an additional review of the storm costs including the allocation of costs to capital. Hearings at the PUCO are scheduled for December 2013. As of September 30, 2013, OPCo recorded $61 million in Regulatory Assets on the balance sheet related to 2012 storm damage. If OPCo is not ultimately permitted to recover these storm costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2009 Fuel Adjustment Clause Audit | ||||||||||
The PUCO selected an outside consultant to conduct an audit of OPCo's FAC for 2009. The outside consultant provided its audit report to the PUCO. In January 2012, the PUCO ordered that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. OPCo recorded a $30 million net favorable adjustment on the statement of income in the second quarter of 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. Management is unable to predict the outcome of any future consultant recommendation regarding valuation of the coal reserve. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2010 and 2011 Fuel Adjustment Clause Audits | ||||||||||
The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO are scheduled for November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009-2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding. | ||||||||||
Ormet | ||||||||||
Ormet, a large aluminum company, has a contract through 2018 to purchase power from OPCo. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, following applications to the PUCO to amend Ormet's power contract with OPCo, Ormet announced that they are unable to emerge from bankruptcy and are shutting down operations effective immediately. Based upon previous PUCO rulings to provide rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider, except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the Economic Development Rider. As of September 30, 2013, OPCo has recorded a regulatory asset of $32 million of Ormet amounts collectible through the Economic Development Rider as a result of these special rate recovery mechanisms and amounts unpaid by Ormet. | ||||||||||
In the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised the issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. | ||||||||||
To the extent amounts referenced above are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Ohio IGCC Plant | ||||||||||
In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of September 30, 2013, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. | ||||||||||
Management cannot predict the outcome of these proceedings concerning the Ohio IGCC plant or what effect, if any, these proceedings could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
3. RATE MATTERS | ||||||||||
As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
OPCo | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Economic Development Rider | $ | 13,693 | $ | 13,213 | ||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 62,677 | 61,828 | ||||||||
Ormet Special Rate Recovery Mechanism | 32,344 | 5,453 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,669 | 30 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 111,383 | $ | 80,524 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Corporate Separation | ||||||||||
In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets at net book value to AEPGenCo. AEPGenCo will also assume the associated generation liabilities. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In October 2013, OPCo filed an application with the PUCO to amend the corporate separation plan by permitting OPCo to retain certain rights to purchase power from OVEC. | ||||||||||
Also in October 2012, filings at the FERC were submitted related to corporate separation. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo. See the “Corporate Separation and Termination of Interconnection Agreement” section of FERC Rate Matters. | ||||||||||
FERC Rate Matters | ||||||||||
Corporate Separation and Termination of Interconnection Agreement – Affecting APCo, I&M and OPCo | ||||||||||
In October 2012, the AEP East Companies submitted several filings with the FERC seeking approval to fully separate OPCo's generation assets from its distribution and transmission operations. The filings requested approval to transfer at net book value (NBV) approximately 9,200 MW of OPCo-owned generation assets to a new wholly-owned company, AEPGenCo. The AEP East Companies also requested FERC approval to transfer at NBV OPCo's current two-thirds ownership (867 MW) in Amos Plant, Unit 3 to APCo and transfer at NBV OPCo's Mitchell Plant to APCo and KPCo in equal one-half interests (780 MW each). These transfers are proposed to be effective December 31, 2013. In April 2013, the FERC issued orders approving the transfer of OPCo's generation assets to AEPGenCo, the Amos Plant and Mitchell Plant asset transfers to APCo and KPCo and the merger of APCo and WPCo. In May 2013, the IEU petitioned the FERC for rehearing of its order granting OPCo authority to implement corporate separation by transferring its generation assets to AEPGenCo. OPCo has contested the petition for rehearing, which remains pending before the FERC. Similar asset transfer filings have been made at the Virginia SCC and the WVPSC. See the “Plant Transfers” section of APCo Rate Matters. | ||||||||||
Additionally, the AEP East Companies requested FERC approval, effective January 1, 2014, to terminate the existing Interconnection Agreement and approve a Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants' respective power supply resources. Under the PCA, APCo and I&M would be individually responsible for planning their respective capacity obligations and there would be no capacity equalization charges/credits on deficit/surplus companies. Further, the PCA allows, but does not obligate, APCo and I&M to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. Intervenors have opposed several of these filings. The AEP East Companies responded to intervenor comments and filed a revised PCA at the FERC in March 2013. The revised PCA included certain clarifying wording changes that have been agreed upon by intervenors. A decision is pending at the FERC. | ||||||||||
In October 2013, the AEP East Companies submitted additional filings with the FERC updating the October 2012 filings to reflect changes necessitated by recent orders from the Virginia SCC and the KPSC related to the proposed asset transfers and to position the company for the final stages of corporate separation. See the “Plant Transfers” section of APCo Rate Matters for a discussion of the Virginia SCC order. | ||||||||||
If APCo and/or I&M experience decreases in revenues or increases in expenses as a result of changes to their relationship with affiliates and are unable to recover the change in revenues and costs through rates, prices or additional sales, it could reduce future net income and cash flows. | ||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Rate Matters | PSO Rate Matters | |||||||||
Oklahoma Environmental Compliance Plan | ||||||||||
In September 2012, PSO filed an environmental compliance plan with the OCC reflecting the retirement of Northeastern Station (NES), Unit 4 in 2016 and additional environmental controls on NES, Unit 3 to continue operations through 2026. As of September 30, 2013, the net book values of NES, Units 3 and 4 were $182 million and $101 million, respectively, before cost of removal, including materials and supplies inventory and CWIP. In August 2013, the OCC dismissed PSO's environmental compliance plan case without prejudice but will permit PSO to seek recovery in a future proceeding. PSO will address the environmental compliance plan issues in future regulatory proceedings when it seeks cost recovery of the plan. If PSO is ultimately not permitted to fully recover its net book value of NES, Units 3 and 4 and other environmental compliance costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
3. RATE MATTERS | ||||||||||
As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
PSO | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 6,968 | $ | - | ||||||
Other Regulatory Assets Not Yet Being Recovered | 822 | 423 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 7,790 | $ | 423 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Southwestern Electric Power Co [Member] | ||||||||||
Rate Matters | SWEPCo Rate Matters | |||||||||
Turk Plant | ||||||||||
SWEPCo constructed the Turk Plant, a new base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which was placed into service in December 2012. SWEPCo owns 73% (440 MW) of the Turk Plant and operates the facility. As of September 30, 2013, SWEPCo's share of incurred construction expenditures for the Turk Plant was approximately $1.8 billion, including AFUDC and capitalized interest of $328 million and related transmission costs of $118 million. As of September 30, 2013, a provision of $173 million has been recorded for costs incurred in excess of a Texas cost cap, resulting in total capitalized expenditures of $1.6 billion. | ||||||||||
The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need (CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certain intervenors, the Arkansas Supreme Court issued a decision that reversed the APSC's grant of the CECPN. In June 2010, in response to an Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. The Arkansas portion of the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. | ||||||||||
The PUCT approved a Certificate of Convenience and Necessity (CCN) for the Turk Plant with the following conditions: (a) a cap on the recovery of jurisdictional capital costs for the Turk Plant based on the previously estimated $1.522 billion projected cash construction cost, excluding related transmission costs, (b) a cap on recovery of annual CO2 emission costs at $28 per ton through the year 2030 and (c) a requirement to hold Texas ratepayers financially harmless from any adverse impact related to the Turk Plant not being fully subscribed to by other utilities or wholesale customers. See the “2012 Texas Base Rate Case” disclosure below for a discussion of a PUCT order on the Texas capital cost cap. SWEPCo appealed the PUCT's order contending the two cost cap restrictions are unlawful. The Texas Industrial Energy Consumers (TIEC) filed an appeal contending that the PUCT's grant of a conditional CCN for the Turk Plant should be revoked because the Turk Plant is unnecessary to serve retail customers. The Texas District Court and the Texas Court of Appeals affirmed the PUCT's order in all respects. In March 2013, SWEPCo and the TIEC's petitions for review at the Supreme Court of Texas were denied and in August 2013, SWEPCo and the TIEC's motions for rehearing at the Supreme Court of Texas were denied. | ||||||||||
If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2012 Texas Base Rate Case | ||||||||||
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates by $83 million, primarily due to the Turk Plant, based upon an 11.25% return on common equity to be effective January 2013. The requested base rate increase included a return on and of the Texas jurisdictional share (approximately 33%) of the Turk Plant generation investment as of December 2011, total Turk Plant related estimated transmission investment costs and associated operation and maintenance costs. The filing also (a) increased depreciation expense due to the decrease in the average remaining life of the Welsh Plant to account for the change in the retirement date of the Welsh Plant, Unit 2 from 2040 to 2016, (b) proposed increased vegetation management expenditures and (c) included a return on and of the Stall Unit as of December 2011 and associated operation and maintenance costs. | ||||||||||
In September 2012, an Administrative Law Judge (ALJ) issued an order that granted the establishment of SWEPCo's existing rates as temporary rates beginning in late January 2013, subject to true-up to the final PUCT-approved rates. In May 2013, the ALJ issued a proposal for decision recommending a rate increase but found SWEPCo imprudent for failing to cancel the Turk Plant in 2010. | ||||||||||
The PUCT rejected the ALJ's imprudence recommendation, but during a September 2013 open meeting, the PUCT stated that it would limit the recovery of the investment in the Turk Plant by imposing a Texas jurisdictional cost cap established in the recently concluded Certificate of Convenience and Necessity (CCN) case appeal discussed above (the Texas capital cost cap). The PUCT also provided new details on how the cost cap would be applied. In October 2013, the PUCT issued an order with the determination that the Turk Plant Texas capital cost cap also limited SWEPCo's recovery of AFUDC in addition to its recovery of cash construction costs. As a result of the determination that AFUDC was to be included in the cap, in the third quarter of 2013, SWEPCo recorded an additional pretax impairment of $111 million in Asset Impairments and Other Related Charges on the statement of income. The order approved an annual rate increase of approximately $39 million based upon a return on common equity of 9.65%. As a result of this approval, SWEPCo retroactively applied these rates back to the end of January 2013. The approval also provided for the following: (a) no disallowances to the existing book investment in the Stall Plant, and (b) the exclusion, until SWEPCo files and obtains approval of a Transmission Cost Recovery Rider, of the Turk Plant transmission line investment that was not in service at the end of the test year. Additionally, the PUCT determined that it would defer consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of September 30, 2013, the net book value of Welsh Plant, Unit 2 was $94 million, before cost of removal, including materials and supplies inventory and CWIP. Requests for rehearing may be filed within 30 days of receipt of the PUCT order. SWEPCo intends to file a motion for rehearing with the PUCT in late October 2013. | ||||||||||
If SWEPCo cannot ultimately recover its Texas jurisdictional share of the investment and expenses related to the Turk Plant, transmission lines or Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2012 Louisiana Formula Rate Filing | ||||||||||
In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit, subject to refund based on the staff review of the cost of service and the prudence review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Flint Creek Plant Environmental Controls | ||||||||||
In February 2012, SWEPCo filed a petition with the APSC seeking a declaratory order to install environmental controls at the Flint Creek Plant to comply with the standards established by the CAA. The estimated cost of the project is $408 million, excluding AFUDC and company overheads. As a joint owner of the Flint Creek Plant, SWEPCo's portion of those costs is estimated at $204 million. In July 2013, the APSC approved the request to install environmental controls at the Flint Creek Plant. | ||||||||||
3. RATE MATTERS | ||||||||||
As discussed in the 2012 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2012 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2013 and updates the 2012 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
SWEPCo | ||||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Rate Case Expenses | $ | 7,539 | $ | 4,517 | ||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,143 | 2,295 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,585 | 2,188 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 11,267 | $ | 9,000 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. |
Commitments_Guarantees_and_Con
Commitments, Guarantees and Contingencies | 9 Months Ended | |||||||||
Sep. 30, 2013 | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against us cannot be predicted. 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 our financial statements. The Commitments, Guarantees and Contingencies note within our 2012 Annual Report should be read in conjunction with this report. | ||||||||||
GUARANTEES | ||||||||||
We record liabilities for guarantees 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 | ||||||||||
We enter into standby letters of credit with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. | ||||||||||
We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit. As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were $185 million with maturities ranging from October 2013 to November 2014. | ||||||||||
We have $402 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $407 million. The letters of credit have maturities ranging from March 2014 to March 2015. | ||||||||||
Guarantees of Third-Party Obligations | ||||||||||
SWEPCo | ||||||||||
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, we estimate the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2013, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $13 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on our condensed balance sheets. | ||||||||||
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. | ||||||||||
Indemnifications and Other Guarantees | ||||||||||
Contracts | ||||||||||
We enter into several 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, our exposure generally does not exceed the sale price. The status of certain sale agreements is discussed in the 2012 Annual Report “Dispositions” section of Note 6. As of September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
Master Lease Agreements | ||||||||||
We lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, we are 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 unamortized balance. As of September 30, 2013, the maximum potential loss for these lease agreements was approximately $20 million assuming the fair value of the equipment is zero at the end of the lease term. | ||||||||||
Railcar Lease | ||||||||||
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $14 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2013. | ||||||||||
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss. | ||||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. | ||||||||||
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation | ||||||||||
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, our generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely. | ||||||||||
In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M's reserve is approximately $10 million. As the remediation work is completed, I&M's cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. We cannot predict the amount of additional cost, if any. | ||||||||||
NUCLEAR CONTINGENCIES | ||||||||||
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. | ||||||||||
Nuclear Incident Insurance | ||||||||||
Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion. Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
OPERATIONAL CONTINGENCIES | ||||||||||
Rockport Plant Litigation | ||||||||||
In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants' actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. In October 2013, we filed a motion to dismiss the case. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring. | ||||||||||
Natural Gas Markets Lawsuits | ||||||||||
In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases. The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. AEP filed a motion with the appellate court for rehearing on the issue of whether the district court had personal jurisdiction of AEP in the two referenced cases. No decision has been rendered on that motion. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending. We will continue to defend the cases. We believe the provision we have is adequate. | ||||||||||
Appalachian Power Co [Member] | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their 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. 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. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report. | ||||||||||
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 – Affecting APCo, I&M, OPCo and SWEPCo | ||||||||||
Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. | ||||||||||
The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows: | ||||||||||
Bilateral | Maturity of | |||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
Contracts | ||||||||||
The Registrant Subsidiaries enter 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 September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA. | ||||||||||
Master Lease Agreements | ||||||||||
The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, the Registrant Subsidiaries are 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 unamortized balance. As of September 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: | ||||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. | ||||||||||
Indiana Michigan Power Co [Member] | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their 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. 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. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report. | ||||||||||
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 – Affecting APCo, I&M, OPCo and SWEPCo | ||||||||||
Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. | ||||||||||
AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: | ||||||||||
Company | Amount | Maturity | ||||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows: | ||||||||||
Bilateral | Maturity of | |||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
Contracts | ||||||||||
The Registrant Subsidiaries enter 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 September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA. | ||||||||||
Master Lease Agreements | ||||||||||
The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, the Registrant Subsidiaries are 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 unamortized balance. As of September 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: | ||||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Railcar Lease | ||||||||||
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $14 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2013. | ||||||||||
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. | ||||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. | ||||||||||
The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M | ||||||||||
By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generating plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrant Subsidiaries currently incur costs to dispose of these substances safely. | ||||||||||
In March 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M's reserve is approximately $10 million. As the remediation work is completed, I&M's cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any. | ||||||||||
NUCLEAR CONTINGENCIES – AFFECTING I&M | ||||||||||
I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. | ||||||||||
Nuclear Incident Insurance | ||||||||||
Prior to April 2013, I&M carried insurance coverage for a nuclear or nonnuclear incident at the Cook Plant for property damage, decommissioning and decontamination in the amount of $2.8 billion. Effective April 2013, insurance coverage for a nonnuclear incident at the Cook Plant was reduced to $1.7 billion. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds and recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
OPERATIONAL CONTINGENCIES | ||||||||||
Rockport Plant Litigation – Affecting I&M | ||||||||||
In July 2013, the Wilmington Trust Company filed a complaint in Federal Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants' actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. In October 2013, management filed a motion to dismiss the case. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. | ||||||||||
Ohio Power Co [Member] | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their 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. 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. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report. | ||||||||||
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 – Affecting APCo, I&M, OPCo and SWEPCo | ||||||||||
Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. | ||||||||||
AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: | ||||||||||
Company | Amount | Maturity | ||||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
The Registrant Subsidiaries have $357 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $361 million as follows: | ||||||||||
Bilateral | Maturity of | |||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
Contracts | ||||||||||
The Registrant Subsidiaries enter 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 September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA. | ||||||||||
Master Lease Agreements | ||||||||||
The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, the Registrant Subsidiaries are 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 unamortized balance. As of September 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: | ||||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. | ||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their 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. 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. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report. | ||||||||||
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. | ||||||||||
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
Contracts | ||||||||||
The Registrant Subsidiaries enter 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 September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA. | ||||||||||
Master Lease Agreements | ||||||||||
The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, the Registrant Subsidiaries are 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 unamortized balance. As of September 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: | ||||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. | ||||||||||
Southwestern Electric Power Co [Member] | ||||||||||
Commitments, Guarantees and Contingencies | 4. COMMITMENTS, GUARANTEES AND CONTINGENCIES | |||||||||
The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their 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. 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. The Commitments, Guarantees and Contingencies note within the 2012 Annual Report should be read in conjunction with this report. | ||||||||||
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 – Affecting APCo, I&M, OPCo and SWEPCo | ||||||||||
Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves. | ||||||||||
AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of September 30, 2013, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: | ||||||||||
Company | Amount | Maturity | ||||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
Guarantees of Third-Party Obligations – Affecting SWEPCo | ||||||||||
As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provides guarantees of mine reclamation of $115 million. Since SWEPCo uses self-bonding, the guarantee provides for SWEPCo to commit to use its resources to complete the reclamation in the event the work is not completed by Sabine. This guarantee ends upon depletion of reserves and completion of final reclamation. Based on the latest study completed in 2010, it is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of approximately $58 million. Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of September 30, 2013, SWEPCo has collected approximately $63 million through a rider for final mine closure and reclamation costs, of which $13 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $50 million is recorded in Asset Retirement Obligations on SWEPCo's condensed balance sheets. | ||||||||||
Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. | ||||||||||
Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
Contracts | ||||||||||
The Registrant Subsidiaries enter 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 September 30, 2013, there were no material liabilities recorded for any indemnifications. | ||||||||||
APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of the AEP East Companies related to power purchase and sale activity pursuant to the SIA. PSO and SWEPCo are jointly and severally liable for activity conducted by AEPSC on behalf of PSO and SWEPCo related to power purchase and sale activity pursuant to the SIA. | ||||||||||
Master Lease Agreements | ||||||||||
The Registrant Subsidiaries lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or 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, the Registrant Subsidiaries are 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 unamortized balance. As of September 30, 2013, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows: | ||||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Railcar Lease | ||||||||||
In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $14 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of September 30, 2013. | ||||||||||
Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, management believes that the fair value would produce a sufficient sales price to avoid any loss. | ||||||||||
ENVIRONMENTAL CONTINGENCIES | ||||||||||
Carbon Dioxide Public Nuisance Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In October 2009, the Fifth Circuit Court of Appeals reversed a decision by the Federal District Court for the District of Mississippi dismissing state common law nuisance claims in a putative class action by Mississippi residents asserting that CO2 emissions exacerbated the effects of Hurricane Katrina. The Fifth Circuit held that there was no exclusive commitment of the common law issues raised in plaintiffs' complaint to a coordinate branch of government and that no initial policy determination was required to adjudicate these claims. The court granted petitions for rehearing. An additional recusal left the Fifth Circuit without a quorum to reconsider the decision and the appeal was dismissed, leaving the district court's decision in place. Plaintiffs filed a petition with the U.S. Supreme Court asking the court to remand the case to the Fifth Circuit and reinstate the panel decision. The petition was denied in January 2011. Plaintiffs refiled their complaint in federal district court. The court ordered all defendants to respond to the refiled complaints in October 2011. In March 2012, the court granted the defendants' motion for dismissal on several grounds, including the doctrine of collateral estoppel and the applicable statute of limitations. In May 2013, the U.S. Court of Appeals for the Fifth Circuit affirmed the district court's dismissal of the complaint. The plaintiffs did not appeal to the U.S. Supreme Court. | ||||||||||
Alaskan Villages' Claims – Affecting APCo, I&M, OPCo, PSO and SWEPCo | ||||||||||
In 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a lawsuit in Federal Court in the Northern District of California against AEP, AEPSC and 22 other unrelated defendants including oil and gas companies, a coal company and other electric generating companies. The complaint alleges that the defendants' emissions of CO2 contribute to global warming and constitute a public and private nuisance and that the defendants are acting together. The complaint further alleges that some of the defendants, including AEP, conspired to create a false scientific debate about global warming in order to deceive the public and perpetuate the alleged nuisance. The plaintiffs also allege that the effects of global warming will require the relocation of the village at an alleged cost of $95 million to $400 million. In October 2009, the judge dismissed plaintiffs' federal common law claim for nuisance, finding the claim barred by the political question doctrine and by plaintiffs' lack of standing to bring the claim. The judge also dismissed plaintiffs' state law claims without prejudice to refiling in state court. In September 2012, the Ninth Circuit Court of Appeals affirmed the trial court's decision, holding that the CAA displaced Kivalina's claims for damages. Plaintiffs filed seeking further review in the U.S. Supreme Court. In May 2013, the U.S. Supreme Court denied the plaintiffs' request for review. |
Aquisitions_and_Dispositions
Aquisitions and Dispositions | 9 Months Ended |
Sep. 30, 2013 | |
Acquisitions, Dispositions and Impairments | 5. ACQUISITION AND IMPAIRMENTS |
ACQUISITION | |
2012 | |
BlueStar Energy (Generation and Marketing segment) | |
In March 2012, we completed the acquisition of BlueStar Energy Holdings, Inc. (BlueStar) and its independent retail electric supplier BlueStar Energy Solutions for $70 million. This transaction also included goodwill of $15 million, intangible assets associated with sales contracts and customer accounts of $58 million and liabilities associated with supply contracts of $25 million. BlueStar has been in operation since 2002. Beginning in June 2012, BlueStar began doing business as AEP Energy. AEP Energy provides electric supply for retail customers in Ohio, Illinois and other deregulated electricity markets and also provides energy solutions throughout the United States, including demand response and energy efficiency services. | |
IMPAIRMENTS | |
2013 | |
Turk Plant (Utility Operations segment) | |
In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap. See the “2012 Texas Base Rate Case” section of Note 3. | |
Big Sandy Plant, Unit 2 FGD Project (Utility Operations segment) | |
In the third quarter of 2013, KPCo recorded a pretax write-off of $33 million in Asset Impairments and Other Related Charges on the statement of income primarily related to the Big Sandy Plant, Unit 2 FGD project. See the “Plant Transfer” section of Note 3. | |
Muskingum River Plant, Unit 5 (Utility Operations segment) | |
In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo's 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, we re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. Management expects to retire the plant in 2015. | |
2012 | |
Turk Plant (Utility Operations segment) | |
In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant. | |
Ohio Power Co [Member] | |
Acquisitions, Dispositions and Impairments | 5. DISPOSITION AND IMPAIRMENTS |
DISPOSITION | |
2013 | |
Conesville Coal Preparation Plant – Affecting OPCo | |
In April 2013, OPCo closed on the sale of its Conesville Coal Preparation Plant. This sale did not have a significant impact on OPCo's financial statements. | |
IMPAIRMENTS | |
2013 | |
Muskingum River Plant, Unit 5 – Affecting OPCo | |
In May 2013, the U.S. District Court for the Southern District of Ohio approved a modification to the consent decree, which was initially entered into in 2007, requiring certain types of pollution control equipment to be installed at certain AEP plants, including OPCo's 600 MW Muskingum River Plant, Unit 5 (MR5) coal-fired generation plant. Under the modification to the consent decree, OPCo has the option to cease burning coal and retire MR5 in 2015 or to cease burning coal in 2015 and complete a natural gas refueling project no later than June 2017. In the second quarter of 2013, based on the approval of the modified consent decree and changes in other market factors, management re-evaluated potential courses of action with respect to the planned operation of MR5 and concluded that completion of a refueling project, which would have extended the useful life of MR5, is remote. As a result, management completed an impairment analysis and concluded that MR5 was impaired. Under a market-based value approach, using level 3 unobservable inputs, management determined that the fair value of this generating unit was zero based on the lack of installed environmental control equipment and the nature and condition of this generating unit. In the second quarter of 2013, OPCo recorded a pretax impairment of $154 million in Asset Impairments and Other Related Charges on the statement of income which includes a $6 million pretax impairment of related material and supplies inventory. Management expects to retire the plant in 2015. | |
Southwestern Electric Power Co [Member] | |
Acquisitions, Dispositions and Impairments | 5. DISPOSITION AND IMPAIRMENTS |
IMPAIRMENTS | |
2013 | |
Turk Plant – Affecting SWEPCo | |
In the third quarter of 2013, SWEPCo recorded a pretax write-off of $111 million in Asset Impairments and Other Related Charges on the statement of income related to AFUDC on the Turk Plant that was included in the Texas capital cost cap. See the “2012 Texas Base Rate Case” section of Note 3. | |
2012 | |
Turk Plant – Affecting SWEPCo | |
In 2012, SWEPCo recorded a pretax write-off of $13 million in Asset Impairments and Other Related Charges on the statement of income related to unrecoverable construction costs subject to the Texas capital costs cap portion of the Turk Plant. |
Benefit_Plans
Benefit Plans | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 17 | $ | 19 | $ | 5 | $ | 12 | ||||
Interest Cost | 51 | 56 | 18 | 26 | ||||||||
Expected Return on Plan Assets | -69 | -80 | -27 | -26 | ||||||||
Amortization of Transition Obligation | - | - | - | 1 | ||||||||
Amortization of Prior Service Cost (Credit) | 1 | - | -17 | -5 | ||||||||
Amortization of Net Actuarial Loss | 45 | 42 | 16 | 14 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 45 | $ | 37 | $ | -5 | $ | 22 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 52 | $ | 57 | $ | 17 | $ | 35 | ||||
Interest Cost | 152 | 167 | 53 | 78 | ||||||||
Expected Return on Plan Assets | -208 | -239 | -80 | -76 | ||||||||
Amortization of Transition Obligation | - | - | - | 1 | ||||||||
Amortization of Prior Service Cost (Credit) | 2 | - | -52 | -14 | ||||||||
Amortization of Net Actuarial Loss | 137 | 117 | 48 | 43 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 135 | $ | 102 | $ | -14 | $ | 67 | ||||
Appalachian Power Co [Member] | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
The Registrant Subsidiaries participate 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. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
APCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,543 | $ | 1,892 | $ | 641 | $ | 1,346 | ||||
Interest Cost | 6,916 | 7,553 | 3,363 | 4,616 | ||||||||
Expected Return on Plan Assets | -9,260 | -10,486 | -4,537 | -4,188 | ||||||||
Amortization of Transition Obligation | - | - | - | 201 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 118 | -2,512 | -716 | ||||||||
Amortization of Net Actuarial Loss | 6,256 | 5,085 | 3,063 | 2,631 | ||||||||
Net Periodic Benefit Cost | $ | 5,504 | $ | 4,162 | $ | 18 | $ | 3,890 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 4,628 | $ | 5,674 | $ | 1,924 | $ | 4,040 | ||||
Interest Cost | 20,747 | 22,659 | 10,090 | 13,847 | ||||||||
Expected Return on Plan Assets | -27,780 | -31,458 | -13,610 | -12,564 | ||||||||
Amortization of Transition Obligation | - | - | - | 601 | ||||||||
Amortization of Prior Service Cost (Credit) | 148 | 356 | -7,537 | -2,147 | ||||||||
Amortization of Net Actuarial Loss | 18,769 | 15,254 | 9,187 | 7,894 | ||||||||
Net Periodic Benefit Cost | $ | 16,512 | $ | 12,485 | $ | 54 | $ | 11,671 | ||||
Indiana Michigan Power Co [Member] | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
The Registrant Subsidiaries participate 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. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
I&M | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,183 | $ | 2,477 | $ | 804 | $ | 1,655 | ||||
Interest Cost | 6,025 | 6,562 | 2,056 | 3,196 | ||||||||
Expected Return on Plan Assets | -8,206 | -9,392 | -3,295 | -3,212 | ||||||||
Amortization of Transition Obligation | - | - | - | 33 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 101 | -2,356 | -595 | ||||||||
Amortization of Net Actuarial Loss | 5,422 | 4,392 | 1,882 | 1,762 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 5,473 | $ | 4,140 | $ | -909 | $ | 2,839 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 6,551 | $ | 7,431 | $ | 2,414 | $ | 4,965 | ||||
Interest Cost | 18,075 | 19,684 | 6,166 | 9,589 | ||||||||
Expected Return on Plan Assets | -24,619 | -28,175 | -9,887 | -9,635 | ||||||||
Amortization of Transition Obligation | - | - | - | 99 | ||||||||
Amortization of Prior Service Cost (Credit) | 146 | 305 | -7,066 | -1,787 | ||||||||
Amortization of Net Actuarial Loss | 16,266 | 13,177 | 5,645 | 5,287 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 16,419 | $ | 12,422 | $ | -2,728 | $ | 8,518 | ||||
Ohio Power Co [Member] | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
The Registrant Subsidiaries participate 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. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
OPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,362 | $ | 2,751 | $ | 1,028 | $ | 2,187 | ||||
Interest Cost | 10,268 | 11,298 | 4,100 | 6,047 | ||||||||
Expected Return on Plan Assets | -15,103 | -17,100 | -6,221 | -5,639 | ||||||||
Amortization of Transition Obligation | - | - | - | 26 | ||||||||
Amortization of Prior Service Cost (Credit) | 71 | 186 | -3,219 | -969 | ||||||||
Amortization of Net Actuarial Loss | 9,287 | 7,610 | 3,761 | 3,418 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 6,885 | $ | 4,745 | $ | -551 | $ | 5,070 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 7,107 | $ | 8,253 | $ | 3,627 | $ | 6,561 | ||||
Interest Cost | 30,852 | 33,895 | 12,994 | 18,142 | ||||||||
Expected Return on Plan Assets | -45,386 | -51,301 | -18,698 | -16,917 | ||||||||
Amortization of Transition Obligation | - | - | - | 78 | ||||||||
Amortization of Prior Service Cost (Credit) | 212 | 557 | -9,680 | -2,905 | ||||||||
Amortization of Net Actuarial Loss | 27,905 | 22,830 | 11,843 | 10,252 | ||||||||
Net Periodic Benefit Cost | $ | 20,690 | $ | 14,234 | $ | 86 | $ | 15,211 | ||||
Public Service Co Of Oklahoma [Member] | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
The Registrant Subsidiaries participate 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. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
PSO | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,391 | $ | 1,487 | $ | 343 | $ | 709 | ||||
Interest Cost | 2,748 | 3,076 | 948 | 1,449 | ||||||||
Expected Return on Plan Assets | -3,919 | -4,503 | -1,522 | -1,480 | ||||||||
Amortization of Prior Service Cost (Credit) | 75 | -237 | -1,072 | -270 | ||||||||
Amortization of Net Actuarial Loss | 2,461 | 2,051 | 869 | 797 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,756 | $ | 1,874 | $ | -434 | $ | 1,205 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 4,172 | $ | 4,463 | $ | 1,029 | $ | 2,127 | ||||
Interest Cost | 8,245 | 9,226 | 2,844 | 4,348 | ||||||||
Expected Return on Plan Assets | -11,756 | -13,511 | -4,566 | -4,441 | ||||||||
Amortization of Prior Service Cost (Credit) | 223 | -711 | -3,217 | -809 | ||||||||
Amortization of Net Actuarial Loss | 7,383 | 6,154 | 2,607 | 2,391 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 8,267 | $ | 5,621 | $ | -1,303 | $ | 3,616 | ||||
Southwestern Electric Power Co [Member] | ||||||||||||
Benefit Plans | 6. BENEFIT PLANS | |||||||||||
The Registrant Subsidiaries participate 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. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees. | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three and nine months ended September 30, 2013 and 2012: | ||||||||||||
SWEPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,752 | $ | 1,775 | $ | 424 | $ | 831 | ||||
Interest Cost | 2,864 | 3,134 | 1,075 | 1,669 | ||||||||
Expected Return on Plan Assets | -4,126 | -4,717 | -1,720 | -1,699 | ||||||||
Amortization of Prior Service Cost (Credit) | 87 | -198 | -1,289 | -234 | ||||||||
Amortization of Net Actuarial Loss | 2,553 | 2,083 | 982 | 915 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 3,130 | $ | 2,077 | $ | -528 | $ | 1,482 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 5,258 | $ | 5,324 | $ | 1,270 | $ | 2,493 | ||||
Interest Cost | 8,591 | 9,403 | 3,226 | 5,005 | ||||||||
Expected Return on Plan Assets | -12,381 | -14,150 | -5,160 | -5,096 | ||||||||
Amortization of Prior Service Cost (Credit) | 262 | -595 | -3,867 | -700 | ||||||||
Amortization of Net Actuarial Loss | 7,660 | 6,248 | 2,946 | 2,744 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 9,390 | $ | 6,230 | $ | -1,585 | $ | 4,446 |
Business_Segments
Business Segments | 9 Months Ended | |||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
As outlined in our 2012 Annual Report, our primary business is the generation, transmission and distribution of electricity. Within our Utility Operations segment, we centrally dispatch generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. | ||||||||||||||||||||||||||
Our reportable segments and their related business activities are outlined below: | ||||||||||||||||||||||||||
Utility Operations | ||||||||||||||||||||||||||
Generation of electricity for sale to U.S. retail and wholesale customers. | ||||||||||||||||||||||||||
Transmission and distribution of electricity through assets owned and operated by our ten utility operating companies. | ||||||||||||||||||||||||||
Transmission Operations | ||||||||||||||||||||||||||
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission subsidiaries and transmission joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. | ||||||||||||||||||||||||||
AEP River Operations | ||||||||||||||||||||||||||
Commercial barging operations that transport coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. | ||||||||||||||||||||||||||
Generation and Marketing | ||||||||||||||||||||||||||
Nonregulated generation in ERCOT. | ||||||||||||||||||||||||||
Marketing, risk management and retail activities in ERCOT, PJM and MISO. | ||||||||||||||||||||||||||
The remainder of our activities is presented as All Other. While not considered a reportable segment, All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | ||||||||||||||||||||||||||
The tables below present our reportable segment information for the three and nine months ended September 30, 2013 and 2012 and balance sheet information as of September 30, 2013 and December 31, 2012. These amounts include certain estimates and allocations where necessary. | ||||||||||||||||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 3,788 | $ | 8 | $ | 125 | $ | 251 | $ | 4 | $ | - | $ | 4,176 | ||||||||||||
Other Operating Segments | 31 | 18 | 5 | - | 3 | -57 | - | |||||||||||||||||||
Total Revenues | $ | 3,819 | $ | 26 | $ | 130 | $ | 251 | $ | 7 | $ | -57 | $ | 4,176 | ||||||||||||
Net Income (Loss) | $ | 409 | $ | 22 | $ | -1 | $ | 4 | $ | - | $ | - | $ | 434 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 3,811 | $ | 3 | $ | 142 | $ | 194 | $ | 6 | $ | - | $ | 4,156 | ||||||||||||
Other Operating Segments | 28 | 7 | 5 | - | 4 | -44 | - | |||||||||||||||||||
Total Revenues | $ | 3,839 | $ | 10 | $ | 147 | $ | 194 | $ | 10 | $ | -44 | $ | 4,156 | ||||||||||||
Net Income (Loss) | $ | 471 | $ | 14 | $ | -1 | $ | 10 | $ | -6 | $ | - | $ | 488 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 10,520 | $ | 18 | $ | 365 | $ | 671 | $ | 10 | $ | - | $ | 11,584 | ||||||||||||
Other Operating Segments | 94 | 35 | 15 | - | 6 | -150 | - | |||||||||||||||||||
Total Revenues | $ | 10,614 | $ | 53 | $ | 380 | $ | 671 | $ | 16 | $ | -150 | $ | 11,584 | ||||||||||||
Net Income (Loss) | $ | 980 | $ | 53 | $ | -12 | $ | 15 | $ | 101 | $ | - | $ | 1,137 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 10,407 | $ | 5 | $ | 477 | $ | 427 | $ | 16 | $ | - | $ | 11,332 | ||||||||||||
Other Operating Segments | 75 | 10 | 16 | - | 7 | -108 | - | |||||||||||||||||||
Total Revenues | $ | 10,482 | $ | 15 | $ | 493 | $ | 427 | $ | 23 | $ | -108 | $ | 11,332 | ||||||||||||
Net Income (Loss) | $ | 1,220 | $ | 31 | $ | 11 | $ | 4 | $ | -25 | $ | - | $ | 1,241 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | Reconciling | |||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Adjustments | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | (b) | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
30-Sep-13 | ||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 56,745 | $ | 1,296 | $ | 637 | $ | 627 | $ | 8 | $ | -269 | $ | 59,044 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||
Amortization | 18,791 | 7 | 182 | 268 | 8 | -82 | 19,174 | |||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||
Equipment - Net | $ | 37,954 | $ | 1,289 | $ | 455 | $ | 359 | $ | - | $ | -187 | $ | 39,870 | ||||||||||||
Total Assets | $ | 51,598 | $ | 1,809 | $ | 650 | $ | 1,009 | $ | 17,874 | $ | -17,977 | (c) | $ | 54,963 | |||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | Reconciling | |||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Adjustments | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | (b) | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
31-Dec-12 | ||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 55,707 | $ | 748 | $ | 636 | $ | 621 | $ | 8 | $ | -266 | $ | 57,454 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||
Amortization | 18,344 | 4 | 161 | 246 | 7 | -71 | 18,691 | |||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||
Equipment - Net | $ | 37,363 | $ | 744 | $ | 475 | $ | 375 | $ | 1 | $ | -195 | $ | 38,763 | ||||||||||||
Total Assets | $ | 51,477 | $ | 1,216 | $ | 670 | $ | 1,005 | $ | 17,191 | $ | -17,192 | (c) | $ | 54,367 | |||||||||||
(a) All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | ||||||||||||||||||||||||||
(b) Includes eliminations due to an intercompany capital lease. | ||||||||||||||||||||||||||
(c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. | ||||||||||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. | ||||||||||||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. | ||||||||||||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. | ||||||||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. | ||||||||||||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||||||||
Business Segments | 7. BUSINESS SEGMENTS | |||||||||||||||||||||||||
The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results. |
Derivatives_and_Hedging
Derivatives and Hedging | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. | |||||||||||||||||||||
The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
Volume | |||||||||||||||||||||
September 30, | December 31, | Unit of | |||||||||||||||||||
2013 | 2012 | Measure | |||||||||||||||||||
Primary Risk Exposure | (in millions) | ||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | 464 | 498 | MWhs | ||||||||||||||||||
Coal | 6 | 10 | Tons | ||||||||||||||||||
Natural Gas | 141 | 147 | MMBtus | ||||||||||||||||||
Heating Oil and Gasoline | 5 | 6 | Gallons | ||||||||||||||||||
Interest Rate | $ | 201 | $ | 235 | USD | ||||||||||||||||
Interest Rate and Foreign Currency | $ | 820 | $ | 1,199 | USD | ||||||||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk. | |||||||||||||||||||||
Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” We do not hedge all fuel price risk. | |||||||||||||||||||||
We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. We do not hedge all foreign currency exposure. | |||||||||||||||||||||
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS | |||||||||||||||||||||
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed 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 our derivative instruments, we also apply 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 our 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 our risk management contracts. | |||||||||||||||||||||
According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, we netted $5 million and $7 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $26 million and $50 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities. | |||||||||||||||||||||
The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Gross Amounts | Gross | Net Amounts of | |||||||||||||||||||
Risk Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in millions) | |||||||||||||||||||||
Current Risk Management Assets | $ | 441 | $ | 19 | $ | 4 | $ | 464 | $ | -293 | $ | 171 | |||||||||
Long-term Risk Management Assets | 433 | 6 | 1 | 440 | -126 | 314 | |||||||||||||||
Total Assets | 874 | 25 | 5 | 904 | -419 | 485 | |||||||||||||||
Current Risk Management Liabilities | 389 | 23 | 1 | 413 | -311 | 102 | |||||||||||||||
Long-term Risk Management Liabilities | 301 | 4 | 13 | 318 | -136 | 182 | |||||||||||||||
Total Liabilities | 690 | 27 | 14 | 731 | -447 | 284 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 184 | $ | -2 | $ | -9 | $ | 173 | $ | 28 | $ | 201 | |||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Gross Amounts | Gross | Net Amounts of | |||||||||||||||||||
Risk Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in millions) | |||||||||||||||||||||
Current Risk Management Assets | $ | 589 | $ | 32 | $ | 3 | $ | 624 | $ | -433 | $ | 191 | |||||||||
Long-term Risk Management Assets | 528 | 5 | 1 | 534 | -166 | 368 | |||||||||||||||
Total Assets | 1,117 | 37 | 4 | 1,158 | -599 | 559 | |||||||||||||||
Current Risk Management Liabilities | 546 | 43 | 35 | 624 | -469 | 155 | |||||||||||||||
Long-term Risk Management Liabilities | 383 | 6 | 6 | 395 | -181 | 214 | |||||||||||||||
Total Liabilities | 929 | 49 | 41 | 1,019 | -650 | 369 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 188 | $ | -12 | $ | -37 | $ | 139 | $ | 51 | $ | 190 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include de-designated risk management contracts. | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The table below presents our activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three and Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Location of Gain (Loss) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Utility Operations Revenues | $ | 4 | $ | 5 | $ | 17 | $ | 19 | |||||||||||||
Other Revenues | 9 | 20 | 39 | 28 | |||||||||||||||||
Regulatory Assets (a) | - | 2 | -3 | -35 | |||||||||||||||||
Regulatory Liabilities (a) | -5 | -14 | -10 | 12 | |||||||||||||||||
Total Gain (Loss) on Risk | |||||||||||||||||||||
Management Contracts | $ | 8 | $ | 13 | $ | 43 | $ | 24 | |||||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed statements of income on an accrual basis. | |||||||||||||||||||||
Our 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, we designate 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. During the three and nine months ended September 30, 2013, we recognized gains of $4 million and losses of $8 million, respectively, on our hedging instruments and offsetting losses of $4 million and gains of $8 million, respectively, on our long-term debt. During the three and nine months ended September 30, 2012, we recognized gains of $1 million and $3 million, respectively, on our hedging instruments and offsetting losses of $1 million and $3 million, respectively, on our long-term debt. During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial. | |||||||||||||||||||||
Accounting for Cash Flow Hedging Strategies | |||||||||||||||||||||
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, we designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, we designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013 and 2012, we designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, we did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, we designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 9 | $ | - | $ | 9 | |||||||||||||||
Hedging Liabilities (a) | 11 | 2 | 13 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | -1 | -24 | -25 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | -2 | -4 | -6 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 24 | $ | - | $ | 24 | |||||||||||||||
Hedging Liabilities (a) | 36 | 37 | 73 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | -8 | -30 | -38 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | -8 | -4 | -12 | ||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of September 30, 2013, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 27 months. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
We limit credit risk in our 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. We use Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below investment grade. The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts if our credit ratings had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
September 30, | December 31, | ||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | $ | 3 | $ | 7 | |||||||||||||||||
Amount of Collateral AEP Subsidiaries Would Have Been | |||||||||||||||||||||
Required to Post | 39 | 32 | |||||||||||||||||||
Amount Attributable to RTO and ISO Activities | 38 | 31 | |||||||||||||||||||
In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
September 30, | December 31, | ||||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual | |||||||||||||||||||||
Netting Arrangements | $ | 341 | $ | 469 | |||||||||||||||||
Amount of Cash Collateral Posted | 1 | 8 | |||||||||||||||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 258 | 328 | |||||||||||||||||||
Appalachian Power Co [Member] | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |||||||||||||||||||||
The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |||||||||||||||||||||
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 68,593 | $ | 233 | $ | - | $ | 68,826 | $ | -44,276 | $ | 24,550 | |||||||||
Long-term Risk Management Assets | 32,501 | 226 | - | 32,727 | -11,888 | 20,839 | |||||||||||||||
Total Assets | 101,094 | 459 | - | 101,553 | -56,164 | 45,389 | |||||||||||||||
Current Risk Management Liabilities | 59,793 | 567 | - | 60,360 | -48,719 | 11,641 | |||||||||||||||
Long-term Risk Management Liabilities | 25,003 | 15 | - | 25,018 | -12,937 | 12,081 | |||||||||||||||
Total Liabilities | 84,796 | 582 | - | 85,378 | -61,656 | 23,722 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 16,298 | $ | -123 | $ | - | $ | 16,175 | $ | 5,492 | $ | 21,667 | |||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 127,645 | $ | 338 | $ | - | $ | 127,983 | $ | -97,023 | $ | 30,960 | |||||||||
Long-term Risk Management Assets | 60,498 | 215 | - | 60,713 | -26,353 | 34,360 | |||||||||||||||
Total Assets | 188,143 | 553 | - | 188,696 | -123,376 | 65,320 | |||||||||||||||
Current Risk Management Liabilities | 119,430 | 1,182 | - | 120,612 | -103,914 | 16,698 | |||||||||||||||
Long-term Risk Management Liabilities | 47,281 | 424 | - | 47,705 | -29,229 | 18,476 | |||||||||||||||
Total Liabilities | 166,711 | 1,606 | - | 168,317 | -133,143 | 35,174 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 21,432 | $ | -1,053 | $ | - | $ | 20,379 | $ | 9,767 | $ | 30,146 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The tables below present the Registrant Subsidiaries' activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies. | |||||||||||||||||||||
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |||||||||||||||||||||
The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |||||||||||||||||||||
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 44,988 | $ | 149 | $ | - | $ | 45,137 | $ | -28,987 | $ | 16,150 | |||||||||
Long-term Risk Management Assets | 21,432 | 149 | - | 21,581 | -7,848 | 13,733 | |||||||||||||||
Total Assets | 66,420 | 298 | - | 66,718 | -36,835 | 29,883 | |||||||||||||||
Current Risk Management Liabilities | 40,809 | 370 | - | 41,179 | -31,911 | 9,268 | |||||||||||||||
Long-term Risk Management Liabilities | 16,836 | 7 | - | 16,843 | -8,536 | 8,307 | |||||||||||||||
Total Liabilities | 57,645 | 377 | - | 58,022 | -40,447 | 17,575 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 8,775 | $ | -79 | $ | - | $ | 8,696 | $ | 3,612 | $ | 12,308 | |||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 93,268 | $ | 220 | $ | - | $ | 93,488 | $ | -66,514 | $ | 26,974 | |||||||||
Long-term Risk Management Assets | 41,553 | 148 | - | 41,701 | -18,132 | 23,569 | |||||||||||||||
Total Assets | 134,821 | 368 | - | 135,189 | -84,646 | 50,543 | |||||||||||||||
Current Risk Management Liabilities | 82,433 | 807 | 19,524 | 102,764 | -71,247 | 31,517 | |||||||||||||||
Long-term Risk Management Liabilities | 33,714 | 292 | - | 34,006 | -20,108 | 13,898 | |||||||||||||||
Total Liabilities | 116,147 | 1,099 | 19,524 | 136,770 | -91,355 | 45,415 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 18,674 | $ | -731 | $ | -19,524 | $ | -1,581 | $ | 6,709 | $ | 5,128 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The tables below present the Registrant Subsidiaries' activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies. | |||||||||||||||||||||
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Ohio Power Co [Member] | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |||||||||||||||||||||
The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |||||||||||||||||||||
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 96,628 | $ | 315 | $ | - | $ | 96,943 | $ | -62,765 | $ | 34,178 | |||||||||
Long-term Risk Management Assets | 44,597 | 310 | - | 44,907 | -16,313 | 28,594 | |||||||||||||||
Total Assets | 141,225 | 625 | - | 141,850 | -79,078 | 62,772 | |||||||||||||||
Current Risk Management Liabilities | 84,519 | 774 | - | 85,293 | -68,862 | 16,431 | |||||||||||||||
Long-term Risk Management Liabilities | 34,309 | 18 | - | 34,327 | -17,750 | 16,577 | |||||||||||||||
Total Liabilities | 118,828 | 792 | - | 119,620 | -86,612 | 33,008 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 22,397 | $ | -167 | $ | - | $ | 22,230 | $ | 7,534 | $ | 29,764 | |||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 183,064 | $ | 464 | $ | - | $ | 183,528 | $ | -139,215 | $ | 44,313 | |||||||||
Long-term Risk Management Assets | 85,023 | 303 | - | 85,326 | -37,038 | 48,288 | |||||||||||||||
Total Assets | 268,087 | 767 | - | 268,854 | -176,253 | 92,601 | |||||||||||||||
Current Risk Management Liabilities | 171,397 | 1,658 | - | 173,055 | -148,900 | 24,155 | |||||||||||||||
Long-term Risk Management Liabilities | 66,448 | 596 | - | 67,044 | -41,079 | 25,965 | |||||||||||||||
Total Liabilities | 237,845 | 2,254 | - | 240,099 | -189,979 | 50,120 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 30,242 | $ | -1,487 | $ | - | $ | 28,755 | $ | 13,726 | $ | 42,481 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The tables below present the Registrant Subsidiaries' activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies. | |||||||||||||||||||||
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |||||||||||||||||||||
The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |||||||||||||||||||||
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,394 | $ | 13 | $ | - | $ | 1,407 | $ | -555 | $ | 852 | |||||||||
Long-term Risk Management Assets | 149 | - | - | 149 | - | 149 | |||||||||||||||
Total Assets | 1,543 | 13 | - | 1,556 | -555 | 1,001 | |||||||||||||||
Current Risk Management Liabilities | 1,931 | 12 | - | 1,943 | -555 | 1,388 | |||||||||||||||
Long-term Risk Management Liabilities | - | 7 | - | 7 | -7 | - | |||||||||||||||
Total Liabilities | 1,931 | 19 | - | 1,950 | -562 | 1,388 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -388 | $ | -6 | $ | - | $ | -394 | $ | 7 | $ | -387 | |||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,657 | $ | 42 | $ | - | $ | 1,699 | $ | -1,190 | $ | 509 | |||||||||
Long-term Risk Management Assets | - | - | - | - | 31 | 31 | |||||||||||||||
Total Assets | 1,657 | 42 | - | 1,699 | -1,159 | 540 | |||||||||||||||
Current Risk Management Liabilities | 7,021 | 17 | - | 7,038 | -1,190 | 5,848 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | 31 | 31 | |||||||||||||||
Total Liabilities | 7,021 | 17 | - | 7,038 | -1,159 | 5,879 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -5,364 | $ | 25 | $ | - | $ | -5,339 | $ | - | $ | -5,339 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The tables below present the Registrant Subsidiaries' activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies. | |||||||||||||||||||||
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||||||||
Derivatives and Hedging | 8. DERIVATIVES AND HEDGING | ||||||||||||||||||||
OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS | |||||||||||||||||||||
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |||||||||||||||||||||
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |||||||||||||||||||||
Risk Management Strategies | |||||||||||||||||||||
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |||||||||||||||||||||
The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Fair Value Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |||||||||||||||||||||
Cash Flow Hedging Strategies | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |||||||||||||||||||||
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |||||||||||||||||||||
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the September 30, 2013 and December 31, 2012 condensed balance sheets, the Registrant Subsidiaries netted cash collateral received from third parties against short-term and long-term risk management assets and cash collateral paid to third parties against short-term and long-term risk management liabilities as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,444 | $ | 15 | $ | - | $ | 1,459 | $ | -1,057 | $ | 402 | |||||||||
Long-term Risk Management Assets | 21 | - | - | 21 | - | 21 | |||||||||||||||
Total Assets | 1,465 | 15 | - | 1,480 | -1,057 | 423 | |||||||||||||||
Current Risk Management Liabilities | 1,339 | 14 | - | 1,353 | -1,057 | 296 | |||||||||||||||
Long-term Risk Management Liabilities | - | 8 | - | 8 | -8 | - | |||||||||||||||
Total Liabilities | 1,339 | 22 | - | 1,361 | -1,065 | 296 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 126 | $ | -7 | $ | - | $ | 119 | $ | 8 | $ | 127 | |||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 2,804 | $ | 41 | $ | - | $ | 2,845 | $ | -2,150 | $ | 695 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 2,804 | 41 | - | 2,845 | -2,150 | 695 | |||||||||||||||
Current Risk Management Liabilities | 3,261 | 17 | - | 3,278 | -2,150 | 1,128 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 3,261 | 17 | - | 3,278 | -2,150 | 1,128 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -457 | $ | 24 | $ | - | $ | -433 | $ | - | $ | -433 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
The tables below present the Registrant Subsidiaries' activity of derivative risk management contracts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |||||||||||||||||||||
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |||||||||||||||||||||
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries did not designate any fair value hedging strategies. | |||||||||||||||||||||
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |||||||||||||||||||||
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three and nine months ended September 30, 2013 and 2012, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three and nine months ended September 30, 2013 and 2012, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. | |||||||||||||||||||||
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three and nine months ended September 30, 2013, I&M designated interest rate derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, I&M and SWEPCo designated interest rate derivatives as cash flow hedges. | |||||||||||||||||||||
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and nine months ended September 30, 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and nine months ended September 30, 2012, SWEPCo designated foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three and nine months ended September 30, 2013 and 2012, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. | |||||||||||||||||||||
For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of September 30, 2013 and December 31, 2012 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
The actual amounts reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. | |||||||||||||||||||||
Credit Risk | |||||||||||||||||||||
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |||||||||||||||||||||
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |||||||||||||||||||||
Collateral Triggering Events | |||||||||||||||||||||
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - |
Fair_Value_Measurements
Fair Value Measurements | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. Our market risk oversight staff independently monitors our valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
For our 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. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations 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 our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
We utilize our trustee's external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. | |||||||||||||||||||||
Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |||||||||||||||||||||
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 we could realize in a current market exchange. | |||||||||||||||||||||
The book values and fair values of Long-term Debt as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Book Value | Fair Value | Book Value | Fair Value | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Long-term Debt | $ | 17,568 | $ | 19,316 | $ | 17,757 | $ | 20,907 | |||||||||||||
Fair Value Measurements of Other Temporary Investments | |||||||||||||||||||||
Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and Securities Available for Sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS. | |||||||||||||||||||||
The following is a summary of Other Temporary Investments: | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 188 | $ | - | $ | - | $ | 188 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 79 | - | - | 79 | |||||||||||||||||
Equity Securities - Mutual Funds | 13 | 8 | - | 21 | |||||||||||||||||
Total Other Temporary Investments | $ | 280 | $ | 8 | $ | - | $ | 288 | |||||||||||||
31-Dec-12 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 241 | $ | - | $ | - | $ | 241 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 65 | 2 | - | 67 | |||||||||||||||||
Equity Securities - Mutual Funds | 10 | 6 | - | 16 | |||||||||||||||||
Total Other Temporary Investments | $ | 316 | $ | 8 | $ | - | $ | 324 | |||||||||||||
(a) | Primarily represents amounts held for the repayment of debt. | ||||||||||||||||||||
The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | - | $ | - | $ | - | $ | - | |||||||||||||
Purchases of Investments | 6 | - | 17 | 1 | |||||||||||||||||
Gross Realized Gains on Investment Sales | - | - | - | - | |||||||||||||||||
Gross Realized Losses on Investment Sales | - | - | - | - | |||||||||||||||||
As of September 30, 2013 and December 31, 2012, we had no Other Temporary Investments with an unrealized loss position. As of September 30, 2013, fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. | |||||||||||||||||||||
For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and nine months ended September 30, 2013 and 2012, see Note 2. | |||||||||||||||||||||
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal | |||||||||||||||||||||
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: | |||||||||||||||||||||
Acceptable investments (rated investment grade or above when purchased). | |||||||||||||||||||||
Maximum percentage invested in a specific type of investment. | |||||||||||||||||||||
Prohibition of investment in obligations of AEP or its affiliates. | |||||||||||||||||||||
Withdrawals permitted only for payment of decommissioning costs and trust expenses. | |||||||||||||||||||||
We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. | |||||||||||||||||||||
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds. | |||||||||||||||||||||
The following is a summary of nuclear trust fund investments as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Estimated | Gross | Other-Than- | Estimated | Gross | Other-Than- | ||||||||||||||||
Fair | Unrealized | Temporary | Fair | Unrealized | Temporary | ||||||||||||||||
Value | Gains | Impairments | Value | Gains | Impairments | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Cash and Cash Equivalents | $ | 15 | $ | - | $ | - | $ | 17 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 621 | 34 | -3 | 648 | 58 | -1 | |||||||||||||||
Corporate Debt | 38 | 2 | -2 | 35 | 5 | -1 | |||||||||||||||
State and Local Government | 244 | 1 | - | 270 | 1 | -1 | |||||||||||||||
Subtotal Fixed Income Securities | 903 | 37 | -5 | 953 | 64 | -3 | |||||||||||||||
Equity Securities - Domestic | 921 | 415 | -81 | 736 | 285 | -77 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,839 | $ | 452 | $ | -86 | $ | 1,706 | $ | 349 | $ | -80 | |||||||||
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 250 | $ | 182 | $ | 635 | $ | 699 | |||||||||||||
Purchases of Investments | 264 | 199 | 676 | 744 | |||||||||||||||||
Gross Realized Gains on Investment Sales | 4 | 2 | 16 | 7 | |||||||||||||||||
Gross Realized Losses on Investment Sales | 2 | 1 | 12 | 3 | |||||||||||||||||
The adjusted cost of fixed income securities was $866 million and $889 million as of September 30, 2013 and December 31, 2012, respectively. The adjusted cost of equity securities was $506 million and $451 million as of September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||||
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2013 was as follows: | |||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Within 1 year | $ | 74 | |||||||||||||||||||
1 year – 5 years | 378 | ||||||||||||||||||||
5 years – 10 years | 210 | ||||||||||||||||||||
After 10 years | 241 | ||||||||||||||||||||
Total | $ | 903 | |||||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. Our 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 our valuation techniques. | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 14 | $ | 1 | $ | - | $ | 132 | $ | 147 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 173 | 7 | - | 8 | 188 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 79 | - | - | - | 79 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 21 | - | - | - | 21 | ||||||||||||||||
Total Other Temporary Investments | 273 | 7 | - | 8 | 288 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | 34 | 680 | 147 | -399 | 462 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | 2 | 22 | - | -15 | 9 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 3 | 5 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 9 | 9 | ||||||||||||||||
Total Risk Management Assets | 36 | 704 | 147 | -402 | 485 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 6 | - | - | 9 | 15 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 621 | - | - | 621 | ||||||||||||||||
Corporate Debt | - | 38 | - | - | 38 | ||||||||||||||||
State and Local Government | - | 244 | - | - | 244 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 903 | - | - | 903 | ||||||||||||||||
Equity Securities - Domestic (b) | 921 | - | - | - | 921 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 927 | 903 | - | 9 | 1,839 | ||||||||||||||||
Total Assets | $ | 1,250 | $ | 1,615 | $ | 147 | $ | -253 | $ | 2,759 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | $ | 40 | $ | 613 | $ | 24 | $ | -418 | $ | 259 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 23 | 3 | -15 | 11 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 9 | - | 3 | 12 | ||||||||||||||||
Total Risk Management Liabilities | $ | 40 | $ | 647 | $ | 27 | $ | -430 | $ | 284 | |||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 6 | $ | 1 | $ | - | $ | 272 | $ | 279 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 227 | 5 | - | 9 | 241 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 67 | - | - | - | 67 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 16 | - | - | - | 16 | ||||||||||||||||
Total Other Temporary Investments | 310 | 5 | - | 9 | 324 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | 47 | 938 | 131 | -599 | 517 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | 8 | 28 | - | -12 | 24 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 14 | 14 | ||||||||||||||||
Total Risk Management Assets | 55 | 968 | 131 | -595 | 559 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 7 | - | - | 10 | 17 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 648 | - | - | 648 | ||||||||||||||||
Corporate Debt | - | 35 | - | - | 35 | ||||||||||||||||
State and Local Government | - | 270 | - | - | 270 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 953 | - | - | 953 | ||||||||||||||||
Equity Securities - Domestic (b) | 736 | - | - | - | 736 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 743 | 953 | - | 10 | 1,706 | ||||||||||||||||
Total Assets | $ | 1,114 | $ | 1,927 | $ | 131 | $ | -304 | $ | 2,868 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | $ | 45 | $ | 838 | $ | 45 | $ | -636 | $ | 292 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 48 | - | -12 | 36 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 37 | - | - | 37 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
Total Risk Management Liabilities | $ | 45 | $ | 925 | $ | 45 | $ | -646 | $ | 369 | |||||||||||
(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(b) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(c) 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.'' | |||||||||||||||||||||
(d) The September 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $1 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $4 million in 2013, $48 million in periods 2014-2016, $8 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $6 million in 2013, $60 million in periods 2014-2016, $32 million in periods 2017-2018 and $25 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||||||||||||||
(e) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts. | |||||||||||||||||||||
(f) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(g) The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy: | |||||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Three Months Ended September 30, 2013 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 122 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -2 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 13 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | -3 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -8 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | - | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -2 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | - | ||||||||||||||||||||
Balance as of September 30, 2013 | $ | 120 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Three Months Ended September 30, 2012 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 97 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -5 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 7 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 5 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | 4 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | -3 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -1 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | - | ||||||||||||||||||||
Balance as of September 30, 2012 | $ | 104 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Nine Months Ended September 30, 2013 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 86 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -9 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 32 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | -3 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -7 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 18 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -1 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 4 | ||||||||||||||||||||
Balance as of September 30, 2013 | $ | 120 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Nine Months Ended September 30, 2012 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 69 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -16 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 20 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 2 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | 33 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 10 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -21 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 7 | ||||||||||||||||||||
Balance as of September 30, 2012 | $ | 104 | |||||||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
The following table quantifies the significant unobservable inputs used in developing the fair value of our Level 3 positions as of September 30, 2013: | |||||||||||||||||||||
Fair Value | Valuation | Significant | Input/Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 139 | $ | 23 | Discounted Cash Flow | Forward Market Price (a) | $ | 10.86 | $ | 126.65 | |||||||||||
Counterparty Credit Risk (b) | 374 | ||||||||||||||||||||
FTRs | 8 | 4 | Discounted Cash Flow | Forward Market Price (a) | -11.44 | 13.11 | |||||||||||||||
Total | $ | 147 | $ | 27 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
(b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. | |||||||||||||||||||||
Appalachian Power Co [Member] | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
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 for the Registrant Subsidiaries as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,799 | $ | 85,442 | $ | 13,701 | $ | -55,860 | $ | 45,082 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 452 | - | -145 | 307 | ||||||||||||||||
Total Risk Management Assets | $ | 1,799 | $ | 85,894 | $ | 13,701 | $ | -56,005 | $ | 45,389 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,274 | $ | 80,580 | $ | 2,790 | $ | -61,352 | $ | 23,292 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 575 | - | -145 | 430 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,274 | $ | 81,155 | $ | 2,790 | $ | -61,497 | $ | 23,722 | |||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 4,161 | $ | 166,916 | $ | 17,058 | $ | -123,117 | $ | 65,018 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 498 | - | -196 | 302 | ||||||||||||||||
Total Risk Management Assets | $ | 4,161 | $ | 167,414 | $ | 17,058 | $ | -123,313 | $ | 65,320 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,959 | $ | 158,665 | $ | 6,079 | $ | -132,884 | $ | 33,819 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 1,551 | - | -196 | 1,355 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,959 | $ | 160,216 | $ | 6,079 | $ | -133,080 | $ | 35,174 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: | |||||||||||||||||||||
Three Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2013: | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 11,506 | $ | 1,940 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 2,195 | 850 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 13,701 | $ | 2,790 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
AEP utilizes its trustee's external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. 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 nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |||||||||||||||||||||
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 for the Registrant Subsidiaries as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal | |||||||||||||||||||||
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: | |||||||||||||||||||||
Acceptable investments (rated investment grade or above when purchased). | |||||||||||||||||||||
Maximum percentage invested in a specific type of investment. | |||||||||||||||||||||
Prohibition of investment in obligations of AEP or its affiliates. | |||||||||||||||||||||
Withdrawals permitted only for payment of decommissioning costs and trust expenses. | |||||||||||||||||||||
I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. | |||||||||||||||||||||
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds. | |||||||||||||||||||||
The following is a summary of nuclear trust fund investments as of September 30, 2013 and December 31, 2012: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Estimated | Gross | Other-Than- | Estimated | Gross | Other-Than- | ||||||||||||||||
Fair | Unrealized | Temporary | Fair | Unrealized | Temporary | ||||||||||||||||
Value | Gains | Impairments | Value | Gains | Impairments | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Cash and Cash Equivalents | $ | 14,438 | $ | - | $ | - | $ | 16,783 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 620,944 | 34,377 | -2,662 | 647,918 | 58,268 | -747 | |||||||||||||||
Corporate Debt | 38,272 | 2,684 | -1,786 | 35,399 | 4,903 | -1,352 | |||||||||||||||
State and Local Government | 244,172 | 851 | -358 | 270,090 | 1,006 | -863 | |||||||||||||||
Subtotal Fixed Income Securities | 903,388 | 37,912 | -4,806 | 953,407 | 64,177 | -2,962 | |||||||||||||||
Equity Securities - Domestic | 921,292 | 414,931 | -81,125 | 735,582 | 284,599 | -76,557 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,839,118 | $ | 452,843 | $ | -85,931 | $ | 1,705,772 | $ | 348,776 | $ | -79,519 | |||||||||
The following table provides the securities activity within the decommissioning and SNF trusts for the three and nine months ended September 30, 2013 and 2012: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 249,314 | $ | 181,988 | $ | 635,256 | $ | 698,567 | |||||||||||||
Purchases of Investments | 263,958 | 199,150 | 675,727 | 744,131 | |||||||||||||||||
Gross Realized Gains on Investment Sales | 4,113 | 2,046 | 16,011 | 6,978 | |||||||||||||||||
Gross Realized Losses on Investment Sales | 2,147 | 924 | 11,859 | 3,143 | |||||||||||||||||
The adjusted cost of fixed income securities was $866 million and $889 million as of September 30, 2013 and December 31, 2012, respectively. The adjusted cost of equity securities was $506 million and $451 million as of September 30, 2013 and December 31, 2012, respectively. | |||||||||||||||||||||
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of September 30, 2013 was as follows: | |||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Within 1 year | $ | 73,908 | |||||||||||||||||||
1 year – 5 years | 378,271 | ||||||||||||||||||||
5 years – 10 years | 210,201 | ||||||||||||||||||||
After 10 years | 241,008 | ||||||||||||||||||||
Total | $ | 903,388 | |||||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,184 | $ | 56,155 | $ | 9,015 | $ | -36,670 | $ | 29,684 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 294 | - | -95 | 199 | ||||||||||||||||
Total Risk Management Assets | 1,184 | 56,449 | 9,015 | -36,765 | 29,883 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (c) | 5,684 | - | - | 8,754 | 14,438 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 620,944 | - | - | 620,944 | ||||||||||||||||
Corporate Debt | - | 38,272 | - | - | 38,272 | ||||||||||||||||
State and Local Government | - | 244,172 | - | - | 244,172 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 903,388 | - | - | 903,388 | ||||||||||||||||
Equity Securities - Domestic (d) | 921,292 | - | - | - | 921,292 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 926,976 | 903,388 | - | 8,754 | 1,839,118 | ||||||||||||||||
Total Assets | $ | 928,160 | $ | 959,837 | $ | 9,015 | $ | -28,011 | $ | 1,869,001 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 838 | $ | 54,905 | $ | 1,836 | $ | -40,282 | $ | 17,297 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 373 | - | -95 | 278 | ||||||||||||||||
Total Risk Management Liabilities | $ | 838 | $ | 55,278 | $ | 1,836 | $ | -40,377 | $ | 17,575 | |||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 2,858 | $ | 120,242 | $ | 11,717 | $ | -84,474 | $ | 50,343 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 330 | - | -130 | 200 | ||||||||||||||||
Total Risk Management Assets | 2,858 | 120,572 | 11,717 | -84,604 | 50,543 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (c) | 6,508 | - | - | 10,275 | 16,783 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 647,918 | - | - | 647,918 | ||||||||||||||||
Corporate Debt | - | 35,399 | - | - | 35,399 | ||||||||||||||||
State and Local Government | - | 270,090 | - | - | 270,090 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 953,407 | - | - | 953,407 | ||||||||||||||||
Equity Securities - Domestic (d) | 735,582 | - | - | - | 735,582 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 742,090 | 953,407 | - | 10,275 | 1,705,772 | ||||||||||||||||
Total Assets | $ | 744,948 | $ | 1,073,979 | $ | 11,717 | $ | -74,329 | $ | 1,756,315 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,346 | $ | 110,621 | $ | 4,176 | $ | -91,183 | $ | 24,960 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 1,061 | - | -130 | 931 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 19,524 | - | - | 19,524 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,346 | $ | 131,206 | $ | 4,176 | $ | -91,313 | $ | 45,415 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: | |||||||||||||||||||||
Three Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2013: | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 7,571 | $ | 1,276 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 1,444 | 560 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 9,015 | $ | 1,836 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Ohio Power Co [Member] | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |||||||||||||||||||||
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 for the Registrant Subsidiaries as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Other Cash Deposits (e) | $ | 8,022 | $ | 26 | $ | - | $ | 17 | $ | 8,065 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | 2,469 | 119,749 | 18,799 | -78,663 | 62,354 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 616 | - | -198 | 418 | ||||||||||||||||
Total Risk Management Assets | 2,469 | 120,365 | 18,799 | -78,861 | 62,772 | ||||||||||||||||
Total Assets | $ | 10,491 | $ | 120,391 | $ | 18,799 | $ | -78,844 | $ | 70,837 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,748 | $ | 113,044 | $ | 3,828 | $ | -86,197 | $ | 32,423 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 783 | - | -198 | 585 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,748 | $ | 113,827 | $ | 3,828 | $ | -86,395 | $ | 33,008 | |||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Other Cash Deposits (e) | $ | - | $ | 26 | $ | - | $ | 39 | $ | 65 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | 5,848 | 238,254 | 23,973 | -175,890 | 92,185 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 688 | - | -272 | 416 | ||||||||||||||||
Total Risk Management Assets | 5,848 | 238,942 | 23,973 | -176,162 | 92,601 | ||||||||||||||||
Total Assets | $ | 5,848 | $ | 238,968 | $ | 23,973 | $ | -176,123 | $ | 92,666 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 2,753 | $ | 226,536 | $ | 8,544 | $ | -189,616 | $ | 48,217 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 2,175 | - | -272 | 1,903 | ||||||||||||||||
Total Risk Management Liabilities | $ | 2,753 | $ | 228,711 | $ | 8,544 | $ | -189,888 | $ | 50,120 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: | |||||||||||||||||||||
Three Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of September 30, 2013: | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 15,787 | $ | 2,661 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 3,012 | 1,167 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 18,799 | $ | 3,828 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
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 for the Registrant Subsidiaries as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. | |||||||||||||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,543 | $ | - | $ | -552 | $ | 991 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 10 | - | - | 10 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,553 | $ | - | $ | -552 | $ | 1,001 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,931 | $ | - | $ | -559 | $ | 1,372 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 16 | - | - | 16 | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 1,947 | $ | - | $ | -559 | $ | 1,388 | |||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,657 | $ | - | $ | -1,142 | $ | 515 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 42 | - | -17 | 25 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,699 | $ | - | $ | -1,159 | $ | 540 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 7,021 | $ | - | $ | -1,142 | $ | 5,879 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 17 | - | -17 | - | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 7,038 | $ | - | $ | -1,159 | $ | 5,879 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||||||||
Fair Value Measurements | 9. FAIR VALUE MEASUREMENTS | ||||||||||||||||||||
Fair Value Hierarchy and Valuation Techniques | |||||||||||||||||||||
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |||||||||||||||||||||
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |||||||||||||||||||||
Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |||||||||||||||||||||
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 for the Registrant Subsidiaries as of September 30, 2013 and December 31, 2012 are summarized in the following table: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value Measurements of Financial Assets and Liabilities | |||||||||||||||||||||
The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. 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. | |||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (e) | $ | 14,186 | $ | - | $ | - | $ | 3,465 | $ | 17,651 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | - | 1,464 | - | -1,053 | 411 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 12 | - | - | 12 | ||||||||||||||||
Total Risk Management Assets | - | 1,476 | - | -1,053 | 423 | ||||||||||||||||
Total Assets | $ | 14,186 | $ | 1,476 | $ | - | $ | 2,412 | $ | 18,074 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,338 | $ | - | $ | -1,061 | $ | 277 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 19 | - | - | 19 | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 1,357 | $ | - | $ | -1,061 | $ | 296 | |||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 2,804 | $ | - | $ | -2,133 | $ | 671 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 41 | - | -17 | 24 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 2,845 | $ | - | $ | -2,150 | $ | 695 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 3,261 | $ | - | $ | -2,133 | $ | 1,128 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 17 | - | -17 | - | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 3,278 | $ | - | $ | -2,150 | $ | 1,128 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three and nine months ended September 30, 2013 and 2012. | |||||||||||||||||||||
Income_Taxes
Income Taxes | 9 Months Ended |
Sep. 30, 2013 | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
We, along with our subsidiaries, file a consolidated federal income tax return. 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 tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flows or financial condition. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns and we are currently under examination in several state and local jurisdictions. However, we believe that we have filed tax returns with positions that may be challenged by these tax authorities. We believe 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. We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2008. | |
Uncertain Tax Positions | |
In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. We filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, we recognized a tax benefit of $80 million, plus $43 million of pretax interest income in the second quarter of 2013. The tax benefit and interest income resulted in an increase in net income of $108 million, but did not result in the receipt of cash during the second quarter of 2013. | |
The tax benefit associated with the U.K. Windfall Tax was reported as a $64 million unrecognized tax benefit as of December 31, 2012 and was included in the amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate. Therefore, the related amounts reported as of December 31, 2012 have been reduced as of September 30, 2013, due to the recognition of the U.K. Windfall Tax benefit during the second quarter of 2013. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income, cash flows or financial condition. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. | |
Appalachian Power Co [Member] | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, 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. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M's cash flows in 2014. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. | |
Indiana Michigan Power Co [Member] | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, 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. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M's cash flows in 2014. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. | |
Ohio Power Co [Member] | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, 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. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M's cash flows in 2014. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. | |
Public Service Co Of Oklahoma [Member] | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, 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. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M's cash flows in 2014. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. | |
Southwestern Electric Power Co [Member] | |
Income Taxes | 10. INCOME TAXES |
AEP System Tax Allocation Agreement | |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Federal and State Income Tax Audit Status | |
The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The completion of the federal audit did not result in a material impact on net income, cash flow or financial condition. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. | |
The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant Subsidiaries are currently under examination in several state and local jurisdictions. Management believes that previously filed tax returns have positions that may be challenged by these tax authorities. However, 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. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2008. | |
Federal Tax Regulations | |
In the third quarter of 2013, the U.S. Treasury Department issued final regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. The U.S. Treasury Department had previously issued guidance in the form of proposed and temporary regulations which was generally effective for tax years beginning in 2012, which was moved to tax years beginning in 2014 in November, 2012. In addition, the IRS has issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. The impact of these final regulations is not material to net income or financial condition, except for an approximate $10 million reduction to I&M's cash flows in 2014. | |
State Tax Legislation | |
In the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds and thus, the West Virginia corporate income tax rate will be reduced from 7% to 6.5% in 2014. The enacted provisions will not materially impact net income, cash flows or financial condition. |
Financing_Activities
Financing Activities | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
The following table details long-term debt outstanding as of September 30, 2013 and December 31, 2012: | ||||||||||||||||||||
Type of Debt | 30-Sep-13 | 31-Dec-12 | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Senior Unsecured Notes | $ | 11,705 | $ | 12,712 | ||||||||||||||||
Pollution Control Bonds | 1,982 | 1,958 | ||||||||||||||||||
Notes Payable | 425 | 427 | ||||||||||||||||||
Securitization Bonds | 2,338 | 2,281 | ||||||||||||||||||
Spent Nuclear Fuel Obligation (a) | 265 | 265 | ||||||||||||||||||
Other Long-term Debt | 886 | 140 | ||||||||||||||||||
Fair Value of Interest Rate Hedges | -7 | 3 | ||||||||||||||||||
Unamortized Discount, Net | -26 | -29 | ||||||||||||||||||
Total Long-term Debt Outstanding | 17,568 | 17,757 | ||||||||||||||||||
Long-term Debt Due Within One Year | 1,366 | 2,171 | ||||||||||||||||||
Long-term Debt | $ | 16,202 | $ | 15,586 | ||||||||||||||||
(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $308 million as of September 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets. | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount | Rate | Due Date | ||||||||||||||||
Issuances: | (in millions) | (%) | ||||||||||||||||||
AEP | Other Long-term Debt | $ | 200 | (a) | Variable | 2015 | ||||||||||||||
APCo | Pollution Control Bonds | 30 | 3.25 | 2018 | ||||||||||||||||
APCo | Pollution Control Bonds | 40 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 600 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 165 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102 | 2.05 | 2020 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEPTCo | Senior Unsecured Notes | 25 | 4.83 | 2043 | ||||||||||||||||
TCC | Other Long-term Debt | 75 | (c) | Variable | 2016 | |||||||||||||||
TCC | Pollution Control Bonds | 120 | 4 | 2030 | ||||||||||||||||
TNC | Other Long-term Debt | 75 | (d) | Variable | 2016 | |||||||||||||||
TNC | Senior Unsecured Notes | 125 | 3.09 | 2023 | ||||||||||||||||
TNC | Senior Unsecured Notes | 75 | 4.48 | 2043 | ||||||||||||||||
Total Issuances | $ | 2,098 | (e) | |||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in millions) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
AEP | Other Long-term Debt | $ | 200 | (a) | Variable | 2015 | ||||||||||||||
APCo | Pollution Control Bonds | 30 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 10 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 15 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 4 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 1 | 6 | 2025 | ||||||||||||||||
I&M | Pollution Control Bonds | 40 | 5.25 | 2025 | ||||||||||||||||
OPCo | Pollution Control Bonds | 56 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225 | 6.38 | 2033 | ||||||||||||||||
SWEPCo | Notes Payable | 3 | 4.58 | 2032 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEP Subsidiaries | Notes Payable | 5 | Variable | 2017 | ||||||||||||||||
AEP Subsidiaries | Notes Payable | 2 | 7.59 - 8.03 | 2026 | ||||||||||||||||
AEGCo | Senior Unsecured Notes | 7 | 6.33 | 2037 | ||||||||||||||||
TCC | Securitization Bonds | 76 | 4.98 | 2013 | ||||||||||||||||
TCC | Securitization Bonds | 67 | 5.96 | 2013 | ||||||||||||||||
TCC | Securitization Bonds | 42 | 5.09 | 2015 | ||||||||||||||||
TCC | Securitization Bonds | 26 | 0.88 | 2017 | ||||||||||||||||
TNC | Senior Unsecured Notes | 225 | 5.5 | 2013 | ||||||||||||||||
Total Retirements and | ||||||||||||||||||||
Principal Payments | $ | 2,281 | ||||||||||||||||||
(a) Draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(b) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
(c) Draw on a $100 million three-year revolving credit facility to be used for general corporate purposes. | ||||||||||||||||||||
(d) Draw on a $75 million three-year revolving credit facility to be used for general corporate purposes. | ||||||||||||||||||||
(e) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances. | ||||||||||||||||||||
In February 2013, we entered into a $1 billion term credit facility due in May 2015. In July 2013, we terminated the $1 billion term credit facility. Also in July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process. Upon entering into the new term credit facility, we repaid the $200 million Long-term Debt and OPCo subsequently borrowed $600 million under the new credit facility. Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo's generation assets to AEPGenCo. Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo's subsequent transfer of certain of those generation assets to APCo and KPCo. | ||||||||||||||||||||
In October 2013, I&M retired $37 million of Notes Payable related to DCC Fuel. | ||||||||||||||||||||
As of September 30, 2013, trustees held on our behalf, $500 million of our reacquired Pollution Control Bonds. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
Parent Restrictions | ||||||||||||||||||||
The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income derives from our common stock equity in the earnings of our utility subsidiaries. | ||||||||||||||||||||
Pursuant to the leverage restrictions in our credit agreements, we must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. None of AEP's retained earnings were restricted for the purpose of the payment of dividends. | ||||||||||||||||||||
Utility Subsidiaries' Restrictions | ||||||||||||||||||||
Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%. | ||||||||||||||||||||
The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Short-term Debt | ||||||||||||||||||||
Our outstanding short-term debt was as follows: | ||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Type of Debt | Amount | Rate (a) | Amount | Rate (a) | ||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||
Securitized Debt for Receivables (b) | $ | 700 | 0.23 | % | $ | 657 | 0.26 | % | ||||||||||||
Commercial Paper | 518 | 0.31 | % | 321 | 0.42 | % | ||||||||||||||
Line of Credit – Sabine (c) | - | - | % | 3 | 1.82 | % | ||||||||||||||
Total Short-term Debt | $ | 1,218 | $ | 981 | ||||||||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | ||||||||||||||||||||
(c) This line of credit does not reduce available liquidity under AEP's credit facilities. | ||||||||||||||||||||
Credit Facilities | ||||||||||||||||||||
For an additional discussion of credit facilities, see “Letters of Credit” section of Note 4. | ||||||||||||||||||||
Securitized Accounts Receivable – AEP Credit | ||||||||||||||||||||
AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies' receivables and accelerate AEP Credit's cash collections. | ||||||||||||||||||||
In June 2013, we amended our receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. We amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
Accounts receivable information for AEP Credit is as follows: | ||||||||||||||||||||
Three Months Ended | Nine Months Ended | |||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(dollars in millions) | ||||||||||||||||||||
Effective Interest Rates on Securitization of | ||||||||||||||||||||
Accounts Receivable | 0.23 | % | 0.26 | % | 0.23 | % | 0.26 | % | ||||||||||||
Net Uncollectible Accounts Receivable | ||||||||||||||||||||
Written Off | $ | 12 | $ | 8 | $ | 26 | $ | 21 | ||||||||||||
September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Accounts Receivable Retained Interest and Pledged as Collateral | ||||||||||||||||||||
Less Uncollectible Accounts | $ | 965 | $ | 835 | ||||||||||||||||
Total Principal Outstanding | 700 | 657 | ||||||||||||||||||
Delinquent Securitized Accounts Receivable | 60 | 37 | ||||||||||||||||||
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | 17 | 21 | ||||||||||||||||||
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | 266 | 316 | ||||||||||||||||||
Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit's delinquent customer accounts receivable represents accounts greater than 30 days past due. | ||||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
In February 2013, AEP entered into a $1 billion credit facility due in May 2015. In July 2013, the $1 billion term credit facility due in May 2015 was terminated. Also in July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process. Upon entering into the new term credit facility, OPCo repaid the $200 million Long-term Debt – Affiliated and subsequently borrowed $600 million Long-term Debt – Nonaffiliated under the new term credit facility. Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo's generation assets to AEPGenCo. Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo's subsequent transfer of certain of those generation assets to APCo and KPCo. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. | ||||||||||||||||||||
Federal Power Act | ||||||||||||||||||||
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. | ||||||||||||||||||||
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo. | ||||||||||||||||||||
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Leverage Restrictions | ||||||||||||||||||||
Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. | ||||||||||||||||||||
Utility Money Pool – 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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility 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 September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2013 are described in the following table: | ||||||||||||||||||||
Net | ||||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table: | ||||||||||||||||||||
Average Interest Rate | Average Interest Rate | |||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 4. | ||||||||||||||||||||
Sale of Receivables – AEP Credit | ||||||||||||||||||||
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. | ||||||||||||||||||||
In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2013 and December 31, 2012 was as follows: | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
In October 2013, I&M retired $37 million of Notes Payable related to DCC Fuel. | ||||||||||||||||||||
As of September 30, 2013, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. | ||||||||||||||||||||
Federal Power Act | ||||||||||||||||||||
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. | ||||||||||||||||||||
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo. | ||||||||||||||||||||
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Leverage Restrictions | ||||||||||||||||||||
Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. | ||||||||||||||||||||
Utility Money Pool – 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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility 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 September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2013 are described in the following table: | ||||||||||||||||||||
Net | ||||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table: | ||||||||||||||||||||
Average Interest Rate | Average Interest Rate | |||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 4. | ||||||||||||||||||||
Sale of Receivables – AEP Credit | ||||||||||||||||||||
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. | ||||||||||||||||||||
In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2013 and December 31, 2012 was as follows: | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
In February 2013, AEP entered into a $1 billion credit facility due in May 2015. In July 2013, the $1 billion term credit facility due in May 2015 was terminated. Also in July 2013, AEPGenCo, APCo, KPCo and OPCo entered into a $1 billion term credit facility due in May 2015 to provide liquidity during the corporate separation process. Upon entering into the new term credit facility, OPCo repaid the $200 million Long-term Debt – Affiliated and subsequently borrowed $600 million Long-term Debt – Nonaffiliated under the new term credit facility. Under the credit facility, OPCo may assign borrowings to AEPGenCo upon the transfer of OPCo's generation assets to AEPGenCo. Subject to regulatory approval, AEPGenCo may further assign a portion of the borrowings to APCo and KPCo, not to exceed $500 million and $250 million, respectively, upon AEPGenCo's subsequent transfer of certain of those generation assets to APCo and KPCo. | ||||||||||||||||||||
As of September 30, 2013, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. | ||||||||||||||||||||
Federal Power Act | ||||||||||||||||||||
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. | ||||||||||||||||||||
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo. | ||||||||||||||||||||
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Leverage Restrictions | ||||||||||||||||||||
Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. | ||||||||||||||||||||
Utility Money Pool – 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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility 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 September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2013 are described in the following table: | ||||||||||||||||||||
Net | ||||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
The activity in the above table does not include short-term lending activity of OPCo's wholly-owned subsidiary, AEPGenCo, which is a participant in the Nonutility Money Pool. The amounts of outstanding borrowings from the Nonutility Money Pool as of September 30, 2013 is included in Advances from Affiliates on OPCo's condensed balance sheet. For the nine months ended September 30, 2013, AEPGenCo had the following activity in the Nonutility Money Pool: | ||||||||||||||||||||
Maximum | Maximum | Average | Average | Borrowings | ||||||||||||||||
Borrowings | Loans | Borrowings | Loans | from the Nonutility | ||||||||||||||||
from the Nonutility | to the Nonutility | from the Nonutility | to the Nonutility | Money Pool as of | ||||||||||||||||
Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
$ | 1,047 | $ | 1,027 | $ | 201 | $ | 208 | $ | 338 | |||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table: | ||||||||||||||||||||
Average Interest Rate | Average Interest Rate | |||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
AEPGenCo's maximum, minimum and average interest rates for funds either borrowed from or loaned to the Nonutility Money Pool for the nine months ended September 30, 2013 are summarized in the following table: | ||||||||||||||||||||
Maximum | Minimum | Maximum | Minimum | Average | Average | |||||||||||||||
Interest Rate | Interest Rate | Interest Rate | Interest Rate | Interest Rate | Interest Rate | |||||||||||||||
for Funds | for Funds | for Funds | for Funds | for Funds | for Funds | |||||||||||||||
Nine Months | Borrowed from | Borrowed from | Loaned to | Loaned to | Borrowed from | Loaned to | ||||||||||||||
Ended | the Nonutility | the Nonutility | the Nonutility | the Nonutility | the Nonutility | the Nonutility | ||||||||||||||
September 30, | Money Pool | Money Pool | Money Pool | Money Pool | Money Pool | Money Pool | ||||||||||||||
2013 | 0.61 | % | 0.53 | % | 0.35 | % | 0.32 | % | 0.56 | % | 0.34 | % | ||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 4. | ||||||||||||||||||||
Sale of Receivables – AEP Credit | ||||||||||||||||||||
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. | ||||||||||||||||||||
In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2013 and December 31, 2012 was as follows: | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. | ||||||||||||||||||||
Federal Power Act | ||||||||||||||||||||
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. | ||||||||||||||||||||
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo. | ||||||||||||||||||||
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Leverage Restrictions | ||||||||||||||||||||
Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. | ||||||||||||||||||||
Utility Money Pool – 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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility 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 September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2013 are described in the following table: | ||||||||||||||||||||
Net | ||||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table: | ||||||||||||||||||||
Average Interest Rate | Average Interest Rate | |||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Sale of Receivables – AEP Credit | ||||||||||||||||||||
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. | ||||||||||||||||||||
In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2013 and December 31, 2012 was as follows: | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Financing Activities | 11. FINANCING ACTIVITIES | |||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2013 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Dividend Restrictions | ||||||||||||||||||||
The Registrant Subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the Registrant Subsidiaries to transfer funds to Parent in the form of dividends. | ||||||||||||||||||||
Federal Power Act | ||||||||||||||||||||
The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. | ||||||||||||||||||||
Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generating plants. Because of their respective ownership of such plants, this reserve applies to APCo, I&M and OPCo. | ||||||||||||||||||||
None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. | ||||||||||||||||||||
Leverage Restrictions | ||||||||||||||||||||
Pursuant to the credit agreement leverage restrictions, APCo, I&M and OPCo must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. | ||||||||||||||||||||
Utility Money Pool – 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, and a Nonutility Money Pool, which funds a majority of AEP's nonutility 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 September 30, 2013 and December 31, 2012 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the nine months ended September 30, 2013 are described in the following table: | ||||||||||||||||||||
Net | ||||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the nine months ended September 30, 2013 and 2012 are summarized for all Registrant Subsidiaries in the following table: | ||||||||||||||||||||
Average Interest Rate | Average Interest Rate | |||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Short-term Debt | ||||||||||||||||||||
The Registrant Subsidiaries' outstanding short-term debt was as follows: | ||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Company | Type of Debt | Amount | Rate (a) | Amount | Rate (a) | |||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||
SWEPCo | Line of Credit – Sabine | $ | - | - | % | $ | 2,603 | 1.82 | % | |||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 4. | ||||||||||||||||||||
Sale of Receivables – AEP Credit | ||||||||||||||||||||
Under a sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit's financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary's receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold. | ||||||||||||||||||||
In June 2013, AEP Credit amended its receivables securitization agreement. The agreement provides a commitment of $700 million from bank conduits to purchase receivables. AEP Credit amended a commitment of $385 million to now expire in June 2014. The remaining commitment of $315 million expires in June 2015. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of September 30, 2013 and December 31, 2012 was as follows: | ||||||||||||||||||||
September 30, | December 31, | |||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 |
Variable_Interest_Entities
Variable Interest Entities | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE's variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently. | |||||||||||||||||||||
We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding and a protected cell of EIS. In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding and our protected cell of EIS that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). | |||||||||||||||||||||
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine's only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo's total billings from Sabine for the three months ended September 30, 2013 and 2012 were $41 million and $35 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $125 million and $126 million, respectively. See the tables below for the classification of Sabine's assets and liabilities on the condensed balance sheets. | |||||||||||||||||||||
I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2013 and 2012 were $32 million and $23 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $96 million and $82 million, respectively. The leases were recorded as capital leases on I&M's balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on our control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. See the tables below for the classification of DCC Fuel's assets and liabilities on the condensed balance sheets. | |||||||||||||||||||||
AEP Credit is a wholly-owned subsidiary of AEP. AEP Credit purchases, without recourse, accounts receivable from certain utility subsidiaries of AEP to reduce working capital requirements. AEP provides a minimum of 5% equity and up to 20% of AEP Credit's short-term borrowing needs in excess of third party financings. Any third party financing of AEP Credit only has recourse to the receivables securitized for such financing. Based on our control of AEP Credit, management has concluded that we are the primary beneficiary and are required to consolidate its assets and liabilities. See the tables below for the classification of AEP Credit's assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivable – AEP Credit” section of Note 11. | |||||||||||||||||||||
Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC's equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $2.1 billion and $2.3 billion as of September 30, 2013 and December 31, 2012, respectively, and are included in current and long-term debt on the condensed balance sheets. Transition Funding has securitized transition assets of $1.9 billion and $2.1 billion as of September 30, 2013 and December 31, 2012, respectively, which are presented separately on the face of the condensed balance sheets. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding's securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding's assets and liabilities on the condensed balance sheets. | |||||||||||||||||||||
Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $267 million as of September 30, 2013, and are included in current and long-term debt on the condensed balance sheet. Ohio Phase-in-Recovery Funding has securitized assets of $137 million as of September 30, 2013, which is presented separately on the face of the condensed balance sheet. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed balance sheet. | |||||||||||||||||||||
Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell's only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate its assets and liabilities. Our insurance premium expense to the protected cell for the three months ended September 30, 2013 and 2012 were $15 million and $16 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $30 million and $31 million, respectively. See the tables below for the classification of the protected cell's assets and liabilities on the condensed balance sheets. The amount reported as equity is the protected cell's policy holders' surplus. | |||||||||||||||||||||
The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. | |||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Ohio | |||||||||||||||||||||
TCC | Phase-in- | Protected | |||||||||||||||||||
SWEPCo | I&M | Transition | Recovery | Cell | |||||||||||||||||
Sabine | DCC Fuel | AEP Credit | Funding | Funding | of EIS | ||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | $ | 65 | $ | 155 | $ | 972 | $ | 197 | $ | 12 | $ | 146 | |||||||||
Net Property, Plant and Equipment | 160 | 181 | - | - | - | - | |||||||||||||||
Other Noncurrent Assets | 56 | 79 | 1 | 1,989 | (a) | 261 | (b) | 4 | |||||||||||||
Total Assets | $ | 281 | $ | 415 | $ | 973 | $ | 2,186 | $ | 273 | $ | 150 | |||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32 | $ | 139 | $ | 856 | $ | 298 | $ | 36 | $ | 46 | |||||||||
Noncurrent Liabilities | 249 | 276 | 1 | 1,870 | 236 | 70 | |||||||||||||||
Equity | - | - | 116 | 18 | 1 | 34 | |||||||||||||||
Total Liabilities and Equity | $ | 281 | $ | 415 | $ | 973 | $ | 2,186 | $ | 273 | $ | 150 | |||||||||
(a) Includes an intercompany item eliminated in consolidation of $84 million. | |||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $121 million. | |||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
TCC | |||||||||||||||||||||
SWEPCo | I&M | Transition | Protected Cell | ||||||||||||||||||
Sabine | DCC Fuel | AEP Credit | Funding | of EIS | |||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | $ | 57 | $ | 133 | $ | 843 | $ | 250 | $ | 130 | |||||||||||
Net Property, Plant and Equipment | 170 | 176 | - | - | - | ||||||||||||||||
Other Noncurrent Assets | 55 | 92 | 1 | 2,167 | (a) | 4 | |||||||||||||||
Total Assets | $ | 282 | $ | 401 | $ | 844 | $ | 2,417 | $ | 134 | |||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32 | $ | 121 | $ | 800 | $ | 304 | $ | 43 | |||||||||||
Noncurrent Liabilities | 250 | 280 | 1 | 2,095 | 66 | ||||||||||||||||
Equity | - | - | 43 | 18 | 25 | ||||||||||||||||
Total Liabilities and Equity | $ | 282 | $ | 401 | $ | 844 | $ | 2,417 | $ | 134 | |||||||||||
(a) Includes an intercompany item eliminated in consolidation of $89 million. | |||||||||||||||||||||
DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC's debt. SWEPCo and CLECO equally approve DHLC's annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo's total billings from DHLC for the three months ended September 30, 2013 and 2012 were $21 million and $20 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $53 million and $54 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. | |||||||||||||||||||||
Our investment in DHLC was: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Capital Contribution from SWEPCo | $ | 8 | $ | 8 | $ | 8 | $ | 8 | |||||||||||||
Retained Earnings | 1 | 1 | 1 | 1 | |||||||||||||||||
SWEPCo's Guarantee of Debt | - | 45 | - | 49 | |||||||||||||||||
Total Investment in DHLC | $ | 9 | $ | 54 | $ | 9 | $ | 58 | |||||||||||||
We and FirstEnergy Corp. (FirstEnergy) have a joint venture in Potomac-Appalachian Transmission Highline, LLC (PATH). PATH is a series limited liability company and was created to construct, through its operating companies, a high-voltage transmission line project in the PJM region. PATH consists of the “West Virginia Series (PATH-WV),” owned equally by subsidiaries of FirstEnergy and AEP, and the “Allegheny Series” which is 100% owned by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it a VIE. The “Allegheny Series” is not considered a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our subsidiaries and FirstEnergy's subsidiaries provide services to the PATH companies through service agreements. The entities recover costs through regulated rates. | |||||||||||||||||||||
In August 2012, the PJM board cancelled the PATH Project, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan. In November 2012, the FERC issued an order accepting AEP's and FirstEnergy's abandonment cost recovery filing which requested authority to recover prudently-incurred costs associated with the PATH Project, subject to refund based on the outcome of hearings and settlement procedures. | |||||||||||||||||||||
Our investment in PATH-WV was: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Capital Contribution from AEP | $ | 19 | $ | 19 | $ | 19 | $ | 19 | |||||||||||||
Retained Earnings | 14 | 14 | 12 | 12 | |||||||||||||||||
Total Investment in PATH-WV | $ | 33 | $ | 33 | $ | 31 | $ | 31 | |||||||||||||
Appalachian Power Co [Member] | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. | |||||||||||||||||||||
SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. | |||||||||||||||||||||
AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. | |||||||||||||||||||||
Total AEPSC billings to the Registrant Subsidiaries were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. | |||||||||||||||||||||
SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. | |||||||||||||||||||||
I&M has nuclear fuel lease agreements with DCC Fuel LLC, DCC Fuel II LLC, DCC Fuel III LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel). DCC Fuel was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended September 30, 2013 and 2012 were $32 million and $23 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $96 million and $82 million, respectively. The leases were recorded as capital leases on I&M's balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months. Based on I&M's control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. See the table below for the classification of DCC Fuel's assets and liabilities on I&M's condensed balance sheets. | |||||||||||||||||||||
The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. | |||||||||||||||||||||
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
September 30, 2013 and December 31, 2012 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
DCC Fuel | |||||||||||||||||||||
ASSETS | 2013 | 2012 | |||||||||||||||||||
Current Assets | $ | 155,448 | $ | 132,886 | |||||||||||||||||
Net Property, Plant and Equipment | 180,541 | 176,065 | |||||||||||||||||||
Other Noncurrent Assets | 78,689 | 92,473 | |||||||||||||||||||
Total Assets | $ | 414,678 | $ | 401,424 | |||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 138,796 | $ | 120,873 | |||||||||||||||||
Noncurrent Liabilities | 275,882 | 280,551 | |||||||||||||||||||
Total Liabilities and Equity | $ | 414,678 | $ | 401,424 | |||||||||||||||||
AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. | |||||||||||||||||||||
Total AEPSC billings to the Registrant Subsidiaries were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to OPCo. AEP guarantees all the debt obligations of AEGCo. I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 11 in the 2012 Annual Report. | |||||||||||||||||||||
Total billings from AEGCo were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 66,114 | $ | 65,051 | $ | 177,840 | $ | 177,790 | |||||||||||||
OPCo | 37,255 | 46,184 | 107,876 | 149,424 | |||||||||||||||||
The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 26,323 | $ | 26,323 | $ | 25,498 | $ | 25,498 | |||||||||||||
OPCo | 9,708 | 9,708 | 16,302 | 16,302 | |||||||||||||||||
Ohio Power Co [Member] | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. | |||||||||||||||||||||
SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. | |||||||||||||||||||||
Ohio Phase-in-Recovery Funding was formed for the sole purpose of issuing and servicing securitization bonds related to phase-in recovery property. Management has concluded that OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding because OPCo has the power to direct the most significant activities of the VIE and OPCo's equity interest could potentially be significant. Therefore, OPCo is required to consolidate Ohio Phase-in-Recovery Funding. The securitized bonds totaled $267 million as of September 30, 2013, and are included in current and long-term debt on the condensed balance sheet. Ohio Phase-in-Recovery Funding has securitized assets of $137 million as of September 30, 2013, which is presented separately on the face of the condensed balance sheet. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. | |||||||||||||||||||||
The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. | |||||||||||||||||||||
OHIO POWER COMPANY AND SUBSIDIARIES | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Ohio | |||||||||||||||||||||
Phase-in- | |||||||||||||||||||||
Recovery | |||||||||||||||||||||
Funding | |||||||||||||||||||||
ASSETS | 2013 | ||||||||||||||||||||
Current Assets | $ | 12,021 | |||||||||||||||||||
Other Noncurrent Assets (a) | 261,005 | ||||||||||||||||||||
Total Assets | $ | 273,026 | |||||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 35,550 | |||||||||||||||||||
Noncurrent Liabilities | 236,139 | ||||||||||||||||||||
Equity | 1,337 | ||||||||||||||||||||
Total Liabilities and Equity | $ | 273,026 | |||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation of $121 million. | |||||||||||||||||||||
AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. | |||||||||||||||||||||
Total AEPSC billings to the Registrant Subsidiaries were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo leases the Lawrenceburg Generating Station to OPCo. AEP guarantees all the debt obligations of AEGCo. I&M and OPCo are considered to have a significant interest in AEGCo due to these transactions. I&M and OPCo are exposed to losses to the extent they cannot recover the costs of AEGCo through their normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M, OPCo and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 11 in the 2012 Annual Report. | |||||||||||||||||||||
Total billings from AEGCo were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 66,114 | $ | 65,051 | $ | 177,840 | $ | 177,790 | |||||||||||||
OPCo | 37,255 | 46,184 | 107,876 | 149,424 | |||||||||||||||||
The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 26,323 | $ | 26,323 | $ | 25,498 | $ | 25,498 | |||||||||||||
OPCo | 9,708 | 9,708 | 16,302 | 16,302 | |||||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. | |||||||||||||||||||||
SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. | |||||||||||||||||||||
AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. | |||||||||||||||||||||
Total AEPSC billings to the Registrant Subsidiaries were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||||||||
Variable Interest Entities | 12. VARIABLE INTEREST ENTITIES | ||||||||||||||||||||
The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. | |||||||||||||||||||||
SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo. | |||||||||||||||||||||
Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine's only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo's total billings from Sabine for the three months ended September 30, 2013 and 2012 were $41 million and $35 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $125 million and $126 million, respectively. See the table below for the classification of Sabine's assets and liabilities on SWEPCo's condensed balance sheets. | |||||||||||||||||||||
The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. | |||||||||||||||||||||
SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
September 30, 2013 and December 31, 2012 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Sabine | |||||||||||||||||||||
ASSETS | 2013 | 2012 | |||||||||||||||||||
Current Assets | $ | 64,737 | $ | 56,535 | |||||||||||||||||
Net Property, Plant and Equipment | 160,575 | 170,436 | |||||||||||||||||||
Other Noncurrent Assets | 55,760 | 55,076 | |||||||||||||||||||
Total Assets | $ | 281,072 | $ | 282,047 | |||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32,005 | $ | 31,446 | |||||||||||||||||
Noncurrent Liabilities | 248,745 | 250,340 | |||||||||||||||||||
Equity | 322 | 261 | |||||||||||||||||||
Total Liabilities and Equity | $ | 281,072 | $ | 282,047 | |||||||||||||||||
DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC's debt. SWEPCo and CLECO equally approve DHLC's annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo's total billings from DHLC for the three months ended September 30, 2013 and 2012 were $21 million and $20 million, respectively, and for the nine months ended September 30, 2013 and 2012 were $53 million and $54 million, respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo's equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo's condensed balance sheets. | |||||||||||||||||||||
SWEPCo's investment in DHLC was: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Capital Contribution from SWEPCo | $ | 7,643 | $ | 7,643 | $ | 7,643 | $ | 7,643 | |||||||||||||
Retained Earnings | 1,102 | 1,102 | 946 | 946 | |||||||||||||||||
SWEPCo's Guarantee of Debt | - | 44,897 | - | 49,564 | |||||||||||||||||
Total Investment in DHLC | $ | 8,745 | $ | 53,642 | $ | 8,589 | $ | 58,153 | |||||||||||||
AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. | |||||||||||||||||||||
Total AEPSC billings to the Registrant Subsidiaries were as follows: | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 |
Sustainable_Cost_Reductions
Sustainable Cost Reductions | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, we initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. We selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate our current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
We recorded a charge of $47 million to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. In addition, the sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Sustainable Cost | ||||||||||||||||||||
Reduction Activity | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance as of December 31, 2012 | $ | 25 | ||||||||||||||||||
Incurred | 16 | |||||||||||||||||||
Settled | -30 | |||||||||||||||||||
Adjustments | -9 | |||||||||||||||||||
Balance as of September 30, 2013 | $ | 2 | ||||||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. Approximately 95% of the expense was within the Utility Operations segment. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We do not expect additional costs to be incurred related to this initiative. | ||||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows: | ||||||||||||||||||||
Company | Total Cost Incurred | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
The Registrant Subsidiaries' sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Expense | Incurred for | Remaining | ||||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative. | ||||||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows: | ||||||||||||||||||||
Company | Total Cost Incurred | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
The Registrant Subsidiaries' sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Expense | Incurred for | Remaining | ||||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative. | ||||||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows: | ||||||||||||||||||||
Company | Total Cost Incurred | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
The Registrant Subsidiaries' sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Expense | Incurred for | Remaining | ||||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative. | ||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows: | ||||||||||||||||||||
Company | Total Cost Incurred | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
The Registrant Subsidiaries' sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Expense | Incurred for | Remaining | ||||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative. | ||||||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Sustainable Cost Reductions | 13. SUSTAINABLE COST REDUCTIONS | |||||||||||||||||||
In April 2012, management initiated a process to identify strategic repositioning opportunities and efficiencies that will result in sustainable cost savings. Management selected a consulting firm to facilitate an organizational and process evaluation and a second firm to evaluate current employee benefit programs. The process resulted in involuntary severances and was completed by the end of the first quarter of 2013. The severance program provides two weeks of base pay for every year of service along with other severance benefits. | ||||||||||||||||||||
The Registrant Subsidiaries recorded charges to Other Operation expense in 2012 primarily related to severance benefits as a result of the sustainable cost reductions initiative. The total amount incurred in 2012 by Registrant Subsidiary was as follows: | ||||||||||||||||||||
Company | Total Cost Incurred | |||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
The Registrant Subsidiaries' sustainable cost reduction activity for the nine months ended September 30, 2013 is described in the following table: | ||||||||||||||||||||
Expense | Incurred for | Remaining | ||||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. Management does not expect additional costs to be incurred related to this initiative. |
Significant_Accounting_Matters1
Significant Accounting Matters (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Basis of Accounting | General |
The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2012 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 26, 2013. | |
Earnings Per Share | Earnings Per Share (EPS) |
Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. | |
Appalachian Power Co [Member] | |
Basis of Accounting | General |
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |
Indiana Michigan Power Co [Member] | |
Basis of Accounting | General |
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |
Ohio Power Co [Member] | |
Basis of Accounting | General |
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |
Public Service Co Of Oklahoma [Member] | |
Basis of Accounting | General |
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. | |
Southwestern Electric Power Co [Member] | |
Basis of Accounting | General |
The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. | |
In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and nine months ended September 30, 2013 is not necessarily indicative of results that may be expected for the year ending December 31, 2013. The condensed financial statements are unaudited and should be read in conjunction with the audited 2012 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2012 as filed with the SEC on February 26, 2013. |
Derivatives_and_Hedging_Polici
Derivatives and Hedging (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
We enter into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. | |
Fair Value Hedging Strategies | |
We enter into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk. | |
Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” We do not hedge all fuel price risk. | |
We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure. | |
At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. We do not hedge all foreign currency exposure. | |
ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS | |
The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed 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 our derivative instruments, we also apply 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 our 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 our risk management contracts. | |
According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed statements of income on an accrual basis. | |
Our 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, we designate 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. | |
Accounting for Cash Flow Hedging Strategies | |
For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. | |
We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. | |
We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
We limit credit risk in our 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. We use Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, we are obligated to post an additional amount of collateral if our credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. | |
Appalachian Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |
Fair Value Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. | |
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. | |
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. | |
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. | |
Indiana Michigan Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |
Fair Value Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. | |
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. | |
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. | |
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. | |
Ohio Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |
Fair Value Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. | |
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. | |
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. | |
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. | |
Public Service Co Of Oklahoma [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |
Fair Value Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. | |
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. | |
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. | |
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. | |
Southwestern Electric Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS |
The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments. | |
STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES | |
Risk Management Strategies | |
The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into power, coal, natural gas, interest rate and, to a lesser degree, heating oil and gasoline, emission allowance and other commodity contracts to manage the risk associated with the energy business. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. | |
Fair Value Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative transactions as part of an overall strategy to manage the mix of fixed-rate and floating-rate debt. Certain interest rate derivative transactions effectively modify an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges. | |
Cash Flow Hedging Strategies | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power, coal, natural gas and heating oil and gasoline (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk. | |
The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. For disclosure purposes, these contracts are included with other hedging activities as “Commodity.” The Registrant Subsidiaries do not hedge all fuel price risk. | |
AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure. | |
At times, the Registrant Subsidiaries are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP's risk management policy, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries do not hedge all foreign currency 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 condensed balance sheet 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, the Registrant Subsidiaries also apply 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,” the Registrant Subsidiaries reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. | |
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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions (APCo, I&M, PSO and SWEPCo) 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 Fair Value Hedging Strategies | |
For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. | |
The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. | |
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), the Registrant Subsidiaries initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains). | |
Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. | |
The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. | |
The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. | |
The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. | |
Credit Risk | |
AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. | |
When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an 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, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. | |
Collateral Triggering Events | |
Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. | |
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. |
Fair_Value_Measurements_Polici
Fair Value Measurements (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. Our market risk oversight staff independently monitors our valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of our Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
For our 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. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations 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 our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
We utilize our trustee's external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. | |
Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |
Fair Values of Long-term Debt | 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 we could realize in a current market exchange. | |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal |
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: | |
Acceptable investments (rated investment grade or above when purchased). | |
Maximum percentage invested in a specific type of investment. | |
Prohibition of investment in obligations of AEP or its affiliates. | |
Withdrawals permitted only for payment of decommissioning costs and trust expenses. | |
We maintain trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. | |
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds. | |
Fair Value Assets and Liabilities Measured on 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. Our 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 our valuation techniques. |
Appalachian Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
Fair Values of Long-term Debt | 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. | |
Fair Value Assets and Liabilities Measured on 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. |
Indiana Michigan Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
AEP utilizes its trustee's external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. 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 nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |
Fair Values of Long-term Debt | 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. | |
Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal | Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal |
Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: | |
Acceptable investments (rated investment grade or above when purchased). | |
Maximum percentage invested in a specific type of investment. | |
Prohibition of investment in obligations of AEP or its affiliates. | |
Withdrawals permitted only for payment of decommissioning costs and trust expenses. | |
I&M maintains trust records for each regulatory jurisdiction. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. | |
I&M records securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both fixed income and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds. | |
Fair Value Assets and Liabilities Measured on 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. |
Ohio Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |
Fair Values of Long-term Debt | 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. | |
Fair Value Assets and Liabilities Measured on 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. |
Public Service Co Of Oklahoma [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
Fair Values of Long-term Debt | 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. | |
Fair Value Assets and Liabilities Measured on 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. |
Southwestern Electric Power Co [Member] | |
Valuation Techniques | Fair Value Hierarchy and Valuation Techniques |
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. The AEP System's market risk oversight staff independently monitors its valuation policies and procedures and provides members of the Commercial Operations Risk Committee (CORC) various daily, weekly and monthly reports, regarding compliance with policies and procedures. The CORC consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Energy Supply, Senior Vice President of Commercial Operations and Chief Risk Officer. | |
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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility. | |
Assets in the nuclear trusts, Other Cash Deposits and Cash and Cash Equivalents 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 domestic 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 and cash equivalents funds. Fixed income securities do not trade on an exchange 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. | |
Fair Values of Long-term Debt | 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. | |
Fair Value Assets and Liabilities Measured on 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. |
Income_Taxes_Policies
Income Taxes (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Income Tax Policy | AEP System Tax Allocation Agreement |
We, along with our subsidiaries, file a consolidated federal income tax return. 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 tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Appalachian Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Indiana Michigan Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Ohio Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Public Service Co Of Oklahoma [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Southwestern Electric Power Co [Member] | |
Income Tax Policy | AEP System Tax Allocation Agreement |
The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their 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 tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. | |
Variable_Interest_Entities_Pol
Variable Interest Entities (Policies) | 9 Months Ended |
Sep. 30, 2013 | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE's variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently. |
Appalachian Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Indiana Michigan Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Ohio Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Public Service Co Of Oklahoma [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Southwestern Electric Power Co [Member] | |
Variable Interest Entities | The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required. |
Significant_Accounting_Matters2
Significant Accounting Matters (Tables) | 9 Months Ended | ||||||||||||||
Sep. 30, 2013 | |||||||||||||||
Basic and Diluted EPS Calculations | Three Months Ended September 30, | ||||||||||||||
2013 | 2012 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 433 | $ | 487 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 486.9 | $ | 0.89 | 485 | $ | 1 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Stock Options | - | - | 0.1 | - | |||||||||||
Restricted Stock Units | 0.4 | - | 0.3 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 487.3 | $ | 0.89 | 485.4 | $ | 1 | |||||||||
Nine Months Ended September 30, | |||||||||||||||
2013 | 2012 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 1,134 | $ | 1,238 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 486.4 | $ | 2.33 | 484.4 | $ | 2.55 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Stock Options | - | - | 0.1 | - | |||||||||||
Restricted Stock Units | 0.4 | - | 0.3 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 486.8 | $ | 2.33 | 484.8 | $ | 2.55 |
Comprehensive_Income_Tables
Comprehensive Income (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Securities | Pension | ||||||||||||||||||
Commodity | Foreign Currency | Available for Sale | and OPEB | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 1 | $ | -25 | $ | 5 | $ | -294 | $ | -313 | ||||||||||
Change in Fair Value Recognized in AOCI | 1 | - | 1 | - | 2 | |||||||||||||||
Amounts Reclassified from AOCI | -3 | 1 | - | 7 | 5 | |||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -2 | 1 | 1 | 7 | 7 | |||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -1 | $ | -24 | $ | 6 | $ | -287 | $ | -306 | ||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Securities | Pension | ||||||||||||||||||
Commodity | Foreign Currency | Available for Sale | and OPEB | Total | ||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -8 | $ | -30 | $ | 4 | $ | -303 | $ | -337 | ||||||||||
Change in Fair Value Recognized in AOCI | 11 | 2 | 2 | - | 15 | |||||||||||||||
Amounts Reclassified from AOCI | -4 | 4 | - | 16 | 16 | |||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 7 | 6 | 2 | 16 | 31 | |||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -1 | $ | -24 | $ | 6 | $ | -287 | $ | -306 | ||||||||||
Reclassifications from Accumulated Other Comprehensive Income | Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Utility Operations Revenues | $ | -1 | ||||||||||||||||||
Other Revenues | -3 | |||||||||||||||||||
Purchased Electricity for Resale | -1 | |||||||||||||||||||
Property, Plant and Equipment | - | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | - | |||||||||||||||||||
Subtotal - Commodity | -5 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 2 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -3 | |||||||||||||||||||
Income Tax (Expense) Credit | -1 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -2 | |||||||||||||||||||
Gains and Losses on Securities Available for Sale | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Interest Expense | - | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -7 | |||||||||||||||||||
Actuarial (Gains)/Losses | 18 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 11 | |||||||||||||||||||
Income Tax (Expense) Credit | 4 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 7 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 5 | ||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Utility Operations Revenues | $ | -1 | ||||||||||||||||||
Other Revenues | -8 | |||||||||||||||||||
Purchased Electricity for Resale | 3 | |||||||||||||||||||
Property, Plant and Equipment | - | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | - | |||||||||||||||||||
Subtotal - Commodity | -6 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 6 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 6 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Gains and Losses on Securities Available for Sale | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Interest Expense | - | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | |||||||||||||||||||
Income Tax (Expense) Credit | - | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -16 | |||||||||||||||||||
Actuarial (Gains)/Losses | 41 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 25 | |||||||||||||||||||
Income Tax (Expense) Credit | 9 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 16 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 16 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Interest Rate | ||||||||||||||||||||
and Foreign | ||||||||||||||||||||
Commodity | Currency | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -14 | $ | -30 | $ | -44 | ||||||||||||||
Changes in Fair Value Recognized in AOCI | 16 | -3 | 13 | |||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI | ||||||||||||||||||||
to Statement of Income/within Balance Sheet: | ||||||||||||||||||||
Utility Operations Revenues | - | - | - | |||||||||||||||||
Other Revenues | -1 | - | -1 | |||||||||||||||||
Purchased Electricity for Resale | - | - | - | |||||||||||||||||
Interest Expense | - | 1 | 1 | |||||||||||||||||
Regulatory Assets (a) | - | - | - | |||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1 | $ | -32 | $ | -31 | ||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Interest Rate | ||||||||||||||||||||
and Foreign | ||||||||||||||||||||
Commodity | Currency | Total | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -3 | $ | -20 | $ | -23 | ||||||||||||||
Changes in Fair Value Recognized in AOCI | -7 | -15 | -22 | |||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI | ||||||||||||||||||||
to Statement of Income/within Balance Sheet: | ||||||||||||||||||||
Utility Operations Revenues | - | - | - | |||||||||||||||||
Other Revenues | -4 | - | -4 | |||||||||||||||||
Purchased Electricity for Resale | 13 | - | 13 | |||||||||||||||||
Interest Expense | - | 3 | 3 | |||||||||||||||||
Regulatory Assets (a) | 2 | - | 2 | |||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1 | $ | -32 | $ | -31 | ||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale | Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 3 | ||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 1 | |||||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income: | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 4 | ||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Securities Available for Sale | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 2 | ||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 2 | |||||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income: | ||||||||||||||||||||
Interest Income | - | |||||||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 4 | ||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | APCo | |||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 197 | $ | 2,583 | $ | -30,615 | $ | -27,835 | ||||||||||||
Change in Fair Value Recognized in AOCI | -47 | - | - | -47 | ||||||||||||||||
Amounts Reclassified from AOCI | -184 | 253 | 359 | 428 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -231 | 253 | 359 | 381 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -34 | $ | 2,836 | $ | -30,256 | $ | -27,454 | ||||||||||||
APCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -644 | $ | 2,077 | $ | -31,331 | $ | -29,898 | ||||||||||||
Change in Fair Value Recognized in AOCI | 684 | - | - | 684 | ||||||||||||||||
Amounts Reclassified from AOCI | -74 | 759 | 1,075 | 1,760 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 610 | 759 | 1,075 | 2,444 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -34 | $ | 2,836 | $ | -30,256 | $ | -27,454 | ||||||||||||
Reclassifications from Accumulated Other Comprehensive Income | APCo | |||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -75 | ||||||||||||||||||
Purchased Electricity for Resale | 21 | |||||||||||||||||||
Other Operation Expense | -14 | |||||||||||||||||||
Maintenance Expense | -11 | |||||||||||||||||||
Property, Plant and Equipment | -15 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -190 | |||||||||||||||||||
Subtotal - Commodity | -284 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 390 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 390 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 106 | |||||||||||||||||||
Income Tax (Expense) Credit | 37 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 69 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,282 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,834 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 552 | |||||||||||||||||||
Income Tax (Expense) Credit | 193 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 359 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 428 | ||||||||||||||||||
APCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -53 | ||||||||||||||||||
Purchased Electricity for Resale | 47 | |||||||||||||||||||
Other Operation Expense | -38 | |||||||||||||||||||
Maintenance Expense | -29 | |||||||||||||||||||
Property, Plant and Equipment | -34 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -9 | |||||||||||||||||||
Subtotal - Commodity | -116 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 1,169 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 1,169 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,053 | |||||||||||||||||||
Income Tax (Expense) Credit | 368 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 685 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -3,847 | |||||||||||||||||||
Actuarial (Gains)/Losses | 5,501 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,654 | |||||||||||||||||||
Income Tax (Expense) Credit | 579 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,075 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,760 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | I&M | |||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 147 | $ | -16,796 | $ | -8,439 | $ | -25,088 | ||||||||||||
Change in Fair Value Recognized in AOCI | -49 | - | - | -49 | ||||||||||||||||
Amounts Reclassified from AOCI | -117 | 410 | 174 | 467 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -166 | 410 | 174 | 418 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -19 | $ | -16,386 | $ | -8,265 | $ | -24,670 | ||||||||||||
I&M | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -446 | $ | -19,647 | $ | -8,790 | $ | -28,883 | ||||||||||||
Change in Fair Value Recognized in AOCI | 443 | 2,248 | - | 2,691 | ||||||||||||||||
Amounts Reclassified from AOCI | -16 | 1,013 | 525 | 1,522 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 427 | 3,261 | 525 | 4,213 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -19 | $ | -16,386 | $ | -8,265 | $ | -24,670 | ||||||||||||
Reclassifications from Accumulated Other Comprehensive Income | I&M | |||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -173 | ||||||||||||||||||
Purchased Electricity for Resale | 47 | |||||||||||||||||||
Other Operation Expense | -8 | |||||||||||||||||||
Maintenance Expense | -5 | |||||||||||||||||||
Property, Plant and Equipment | -10 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -31 | |||||||||||||||||||
Subtotal - Commodity | -180 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 631 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 631 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 451 | |||||||||||||||||||
Income Tax (Expense) Credit | 158 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 293 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -199 | |||||||||||||||||||
Actuarial (Gains)/Losses | 467 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 268 | |||||||||||||||||||
Income Tax (Expense) Credit | 94 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 174 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 467 | ||||||||||||||||||
I&M | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -89 | ||||||||||||||||||
Purchased Electricity for Resale | 115 | |||||||||||||||||||
Other Operation Expense | -23 | |||||||||||||||||||
Maintenance Expense | -14 | |||||||||||||||||||
Property, Plant and Equipment | -20 | |||||||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | 7 | |||||||||||||||||||
Subtotal - Commodity | -24 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 1,558 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 1,558 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 1,534 | |||||||||||||||||||
Income Tax (Expense) Credit | 537 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 997 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -596 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,404 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 808 | |||||||||||||||||||
Income Tax (Expense) Credit | 283 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 525 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,522 | ||||||||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | OPCo | |||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | 289 | $ | 7,415 | $ | -166,369 | $ | -158,665 | ||||||||||||
Distribution of Cook Coal Terminal to Parent | - | - | 19,652 | 19,652 | ||||||||||||||||
Change in Fair Value Recognized in AOCI | -86 | - | - | -86 | ||||||||||||||||
Amounts Reclassified from AOCI | -250 | -339 | 2,985 | 2,396 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -336 | -339 | 2,985 | 2,310 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -47 | $ | 7,076 | $ | -143,732 | $ | -136,703 | ||||||||||||
OPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | -912 | $ | 8,095 | $ | -172,908 | $ | -165,725 | ||||||||||||
Distribution of Cook Coal Terminal to Parent | - | - | 19,652 | 19,652 | ||||||||||||||||
Change in Fair Value Recognized in AOCI | 907 | - | - | 907 | ||||||||||||||||
Amounts Reclassified from AOCI | -42 | -1,019 | 9,524 | 8,463 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 865 | -1,019 | 9,524 | 9,370 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -47 | $ | 7,076 | $ | -143,732 | $ | -136,703 | ||||||||||||
Reclassifications from Accumulated Other Comprehensive Income | OPCo | |||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -461 | ||||||||||||||||||
Purchased Electricity for Resale | 129 | |||||||||||||||||||
Other Operation Expense | -20 | |||||||||||||||||||
Maintenance Expense | -11 | |||||||||||||||||||
Property, Plant and Equipment | -21 | |||||||||||||||||||
Subtotal - Commodity | -384 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Depreciation and Amortization Expense | 2 | |||||||||||||||||||
Interest Expense | -524 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -522 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -906 | |||||||||||||||||||
Income Tax (Expense) Credit | -317 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -589 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,451 | |||||||||||||||||||
Actuarial (Gains)/Losses | 6,044 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 4,593 | |||||||||||||||||||
Income Tax (Expense) Credit | 1,608 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 2,985 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 2,396 | ||||||||||||||||||
OPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | -246 | ||||||||||||||||||
Purchased Electricity for Resale | 309 | |||||||||||||||||||
Other Operation Expense | -57 | |||||||||||||||||||
Maintenance Expense | -26 | |||||||||||||||||||
Property, Plant and Equipment | -44 | |||||||||||||||||||
Subtotal - Commodity | -64 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Depreciation and Amortization Expense | 5 | |||||||||||||||||||
Interest Expense | -1,573 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -1,568 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -1,632 | |||||||||||||||||||
Income Tax (Expense) Credit | -571 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,061 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -4,388 | |||||||||||||||||||
Actuarial (Gains)/Losses | 19,040 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 14,652 | |||||||||||||||||||
Income Tax (Expense) Credit | 5,128 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 9,524 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 8,463 | ||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | PSO | |||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | ||||||||||||||||||||
Commodity | Foreign Currency | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | -21 | $ | 6,081 | $ | 6,060 | ||||||||||||||
Change in Fair Value Recognized in AOCI | 32 | - | 32 | |||||||||||||||||
Amounts Reclassified from AOCI | -14 | -190 | -204 | |||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 18 | -190 | -172 | |||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | 5,891 | $ | 5,888 | ||||||||||||||
PSO | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | ||||||||||||||||||||
Commodity | Foreign Currency | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | 21 | $ | 6,460 | $ | 6,481 | ||||||||||||||
Change in Fair Value Recognized in AOCI | 7 | 1 | 8 | |||||||||||||||||
Amounts Reclassified from AOCI | -31 | -570 | -601 | |||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -24 | -569 | -593 | |||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | 5,891 | $ | 5,888 | ||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income | PSO | |||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -10 | ||||||||||||||||||
Maintenance Expense | -5 | |||||||||||||||||||
Property, Plant and Equipment | -7 | |||||||||||||||||||
Subtotal - Commodity | -22 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | -292 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -292 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -314 | |||||||||||||||||||
Income Tax (Expense) Credit | -110 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -204 | ||||||||||||||||||
PSO | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -25 | ||||||||||||||||||
Maintenance Expense | -9 | |||||||||||||||||||
Property, Plant and Equipment | -14 | |||||||||||||||||||
Subtotal - Commodity | -48 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | -876 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -876 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -924 | |||||||||||||||||||
Income Tax (Expense) Credit | -323 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -601 | ||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | ||||||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | SWEPCo | |||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2013 | $ | -26 | $ | -14,437 | $ | -2,438 | $ | -16,901 | ||||||||||||
Change in Fair Value Recognized in AOCI | 40 | - | - | 40 | ||||||||||||||||
Amounts Reclassified from AOCI | -17 | 566 | -64 | 485 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | 23 | 566 | -64 | 525 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | -13,871 | $ | -2,502 | $ | -16,376 | ||||||||||||
SWEPCo | ||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Cash Flow Hedges | ||||||||||||||||||||
Interest Rate and | Pension | |||||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | |||||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2012 | $ | 22 | $ | -15,571 | $ | -2,311 | $ | -17,860 | ||||||||||||
Change in Fair Value Recognized in AOCI | 13 | - | - | 13 | ||||||||||||||||
Amounts Reclassified from AOCI | -38 | 1,700 | -191 | 1,471 | ||||||||||||||||
Net Current Period Other | ||||||||||||||||||||
Comprehensive Income | -25 | 1,700 | -191 | 1,484 | ||||||||||||||||
Balance in AOCI as of September 30, 2013 | $ | -3 | $ | -13,871 | $ | -2,502 | $ | -16,376 | ||||||||||||
Reclassifications from Accumulated Other Comprehensive Income | SWEPCo | |||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Three Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -12 | ||||||||||||||||||
Maintenance Expense | -7 | |||||||||||||||||||
Property, Plant and Equipment | -8 | |||||||||||||||||||
Subtotal - Commodity | -27 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 872 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 872 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 845 | |||||||||||||||||||
Income Tax (Expense) Credit | 296 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 549 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -446 | |||||||||||||||||||
Actuarial (Gains)/Losses | 348 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -98 | |||||||||||||||||||
Income Tax (Expense) Credit | -34 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -64 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 485 | ||||||||||||||||||
SWEPCo | ||||||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | ||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | ||||||||||||||||||||
Amount of | ||||||||||||||||||||
(Gain) Loss | ||||||||||||||||||||
Reclassified | ||||||||||||||||||||
from AOCI | ||||||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | |||||||||||||||||||
Commodity: | ||||||||||||||||||||
Other Operation Expense | $ | -28 | ||||||||||||||||||
Maintenance Expense | -14 | |||||||||||||||||||
Property, Plant and Equipment | -16 | |||||||||||||||||||
Subtotal - Commodity | -58 | |||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||
Interest Expense | 2,616 | |||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2,616 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,558 | |||||||||||||||||||
Income Tax (Expense) Credit | 896 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,662 | |||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||
Prior Service Cost (Credit) | -1,338 | |||||||||||||||||||
Actuarial (Gains)/Losses | 1,044 | |||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -294 | |||||||||||||||||||
Income Tax (Expense) Credit | -103 | |||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -191 | |||||||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 1,471 | ||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | |||||||||||||||||||
For the Three Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -1,820 | $ | -1,246 | $ | -2,639 | $ | -102 | $ | -97 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | 887 | 1,915 | 126 | 123 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | 1,562 | $ | -19,015 | $ | 8,774 | $ | 6,839 | $ | -16,806 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -1,542 | 1 | 1 | -1 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of June 30, 2012 | $ | -258 | $ | -20,261 | $ | 6,135 | $ | 6,737 | $ | -16,903 | ||||||||||
Changes in Fair Value Recognized in AOCI | 1,302 | -655 | 1,916 | 127 | 122 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -4 | -10 | -23 | - | - | |||||||||||||||
Purchased Electricity for Resale | 35 | 88 | 221 | - | - | |||||||||||||||
Other Operation Expense | -4 | -1 | -6 | - | 1 | |||||||||||||||
Maintenance Expense | 12 | 4 | 7 | 5 | 4 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 1 | - | - | |||||||||||||||
Interest Expense | 261 | 149 | -341 | -190 | 567 | |||||||||||||||
Property, Plant and Equipment | 3 | 1 | 1 | 5 | 3 | |||||||||||||||
Regulatory Assets (a) | 114 | 20 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | ||||||||||||||||||||
Commodity Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -1,309 | $ | -819 | $ | -1,748 | $ | -69 | $ | -62 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -741 | -1,487 | 110 | 106 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | -362 | $ | -257 | $ | -524 | $ | 34 | $ | 34 | ||||||||||
Interest Rate and | ||||||||||||||||||||
Foreign Currency Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | 1,024 | $ | -14,465 | $ | 9,454 | $ | 7,218 | $ | -15,462 | ||||||||||
Changes in Fair Value Recognized in AOCI | - | -6,390 | 1 | 1 | -2,778 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,823 | $ | -20,408 | $ | 8,435 | $ | 6,650 | $ | -16,240 | ||||||||||
Total Contracts | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | ||||||||||||||||||||
Balance in AOCI as of December 31, 2011 | $ | -285 | $ | -15,284 | $ | 7,706 | $ | 7,149 | $ | -15,524 | ||||||||||
Changes in Fair Value Recognized in AOCI | -946 | -7,131 | -1,486 | 111 | -2,672 | |||||||||||||||
Amount of (Gain) or Loss Reclassified | ||||||||||||||||||||
from AOCI to Statement of Income/within | ||||||||||||||||||||
Balance Sheet: | ||||||||||||||||||||
Electric Generation, Transmission, and | ||||||||||||||||||||
Distribution Revenues | -7 | -19 | -47 | - | - | |||||||||||||||
Purchased Electricity for Resale | 411 | 1,074 | 2,806 | - | - | |||||||||||||||
Other Operation Expense | -20 | -11 | -30 | -11 | -8 | |||||||||||||||
Maintenance Expense | 3 | - | -3 | 3 | 1 | |||||||||||||||
Depreciation and Amortization | ||||||||||||||||||||
Expense | - | - | 3 | - | - | |||||||||||||||
Interest Expense | 799 | 447 | -1,023 | -569 | 2,000 | |||||||||||||||
Property, Plant and Equipment | -9 | -6 | -15 | 1 | -3 | |||||||||||||||
Regulatory Assets (a) | 1,515 | 265 | - | - | - | |||||||||||||||
Balance in AOCI as of September 30, 2012 | $ | 1,461 | $ | -20,665 | $ | 7,911 | $ | 6,684 | $ | -16,206 | ||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate_Matters_Tables
Rate Matters (Tables) | 9 Months Ended | |||||||||
Sep. 30, 2013 | ||||||||||
Regulatory Assets Not Yet Being Recovered | Regulatory Assets Not Yet Being Recovered | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
(in millions) | ||||||||||
Noncurrent Regulatory Assets | ||||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Storm Related Costs | $ | 22 | $ | 23 | ||||||
Economic Development Rider | 14 | 13 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 3 | 1 | ||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 153 | 172 | ||||||||
Ormet Special Rate Recovery Mechanism | 32 | 5 | ||||||||
Virginia Environmental Rate Adjustment Clause | 28 | 29 | ||||||||
Expanded Net Energy Charge - Coal Inventory | 21 | - | ||||||||
Under-Recovered Capacity Costs | 16 | - | ||||||||
Mountaineer Carbon Capture and Storage Product Validation Facility | 14 | 14 | ||||||||
Litigation Settlement | - | 11 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 38 | 36 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 341 | $ | 304 | ||||||
Appalachian Power Co [Member] | ||||||||||
Regulatory Assets Not Yet Being Recovered | APCo | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 65,206 | $ | 94,458 | ||||||
Virginia Environmental Rate Adjustment Clause | 28,417 | 29,320 | ||||||||
Expanded Net Energy Charge - Coal Inventory | 20,528 | - | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Product Validation Facility | 14,155 | 14,155 | ||||||||
Dresden Plant Operating Costs | 8,358 | 8,758 | ||||||||
Transmission Agreement Phase-In | 3,313 | 2,992 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,287 | 1,287 | ||||||||
Deferred Wind Power Costs | - | 5,143 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 4,246 | 1,447 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 145,510 | $ | 157,560 | ||||||
Indiana Michigan Power Co [Member] | ||||||||||
Regulatory Assets Not Yet Being Recovered | I&M | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Under-Recovered Capacity Costs | $ | 16,445 | $ | - | ||||||
Indiana Deferred Cook Plant Life Cycle Management Project Costs | 3,198 | - | ||||||||
Litigation Settlement | - | 11,098 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | - | 1,380 | ||||||||
Other Regulatory Asset Not Yet Being Recovered | 3,316 | 786 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 22,959 | $ | 13,264 | ||||||
Ohio Power Co [Member] | ||||||||||
Regulatory Assets Not Yet Being Recovered | OPCo | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Economic Development Rider | $ | 13,693 | $ | 13,213 | ||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 62,677 | 61,828 | ||||||||
Ormet Special Rate Recovery Mechanism | 32,344 | 5,453 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,669 | 30 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 111,383 | $ | 80,524 | ||||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Regulatory Assets Not Yet Being Recovered | PSO | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 6,968 | $ | - | ||||||
Other Regulatory Assets Not Yet Being Recovered | 822 | 423 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 7,790 | $ | 423 | ||||||
Southwestern Electric Power Co [Member] | ||||||||||
Regulatory Assets Not Yet Being Recovered | SWEPCo | |||||||||
September 30, | December 31, | |||||||||
2013 | 2012 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Rate Case Expenses | $ | 7,539 | $ | 4,517 | ||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,143 | 2,295 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,585 | 2,188 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 11,267 | $ | 9,000 |
Commitments_Guarantees_and_Con1
Commitments, Guarantees and Contingencies (Tables) | 9 Months Ended | |||||||||
Sep. 30, 2013 | ||||||||||
Appalachian Power Co [Member] | ||||||||||
Pollution Control Bonds Supported by Bilateral Letters of Credit | Bilateral | Maturity of | ||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Maximum Potential Loss on Master Lease Agreements | Maximum | |||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Indiana Michigan Power Co [Member] | ||||||||||
Maximum Future Payments of Letters of Credit | Company | Amount | Maturity | |||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
Pollution Control Bonds Supported by Bilateral Letters of Credit | Bilateral | Maturity of | ||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Maximum Potential Loss on Master Lease Agreements | Maximum | |||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Ohio Power Co [Member] | ||||||||||
Maximum Future Payments of Letters of Credit | Company | Amount | Maturity | |||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
Pollution Control Bonds Supported by Bilateral Letters of Credit | Bilateral | Maturity of | ||||||||
Pollution | Letters | Bilateral Letters | ||||||||
Company | Control Bonds | of Credit | of Credit | |||||||
(in thousands) | ||||||||||
APCo | $ | 229,650 | $ | 232,293 | March 2014 to March 2015 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
OPCo | 50,000 | 50,575 | Jul-14 | |||||||
Maximum Potential Loss on Master Lease Agreements | Maximum | |||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Maximum Potential Loss on Master Lease Agreements | Maximum | |||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 | |||||||||
Southwestern Electric Power Co [Member] | ||||||||||
Maximum Future Payments of Letters of Credit | Company | Amount | Maturity | |||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-14 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
SWEPCo | 4,448 | Mar-14 | ||||||||
Maximum Potential Loss on Master Lease Agreements | Maximum | |||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,630 | ||||||||
I&M | 2,481 | |||||||||
OPCo | 4,505 | |||||||||
PSO | 1,204 | |||||||||
SWEPCo | 2,441 |
Benefit_Plans_Tables
Benefit Plans (Tables) | 9 Months Ended | |||||||||||
Sep. 30, 2013 | ||||||||||||
Components of Net Periodic Benefit Cost | Other Postretirement | |||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 17 | $ | 19 | $ | 5 | $ | 12 | ||||
Interest Cost | 51 | 56 | 18 | 26 | ||||||||
Expected Return on Plan Assets | -69 | -80 | -27 | -26 | ||||||||
Amortization of Transition Obligation | - | - | - | 1 | ||||||||
Amortization of Prior Service Cost (Credit) | 1 | - | -17 | -5 | ||||||||
Amortization of Net Actuarial Loss | 45 | 42 | 16 | 14 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 45 | $ | 37 | $ | -5 | $ | 22 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 52 | $ | 57 | $ | 17 | $ | 35 | ||||
Interest Cost | 152 | 167 | 53 | 78 | ||||||||
Expected Return on Plan Assets | -208 | -239 | -80 | -76 | ||||||||
Amortization of Transition Obligation | - | - | - | 1 | ||||||||
Amortization of Prior Service Cost (Credit) | 2 | - | -52 | -14 | ||||||||
Amortization of Net Actuarial Loss | 137 | 117 | 48 | 43 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 135 | $ | 102 | $ | -14 | $ | 67 | ||||
Appalachian Power Co [Member] | ||||||||||||
Components of Net Periodic Benefit Cost | APCo | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,543 | $ | 1,892 | $ | 641 | $ | 1,346 | ||||
Interest Cost | 6,916 | 7,553 | 3,363 | 4,616 | ||||||||
Expected Return on Plan Assets | -9,260 | -10,486 | -4,537 | -4,188 | ||||||||
Amortization of Transition Obligation | - | - | - | 201 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 118 | -2,512 | -716 | ||||||||
Amortization of Net Actuarial Loss | 6,256 | 5,085 | 3,063 | 2,631 | ||||||||
Net Periodic Benefit Cost | $ | 5,504 | $ | 4,162 | $ | 18 | $ | 3,890 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 4,628 | $ | 5,674 | $ | 1,924 | $ | 4,040 | ||||
Interest Cost | 20,747 | 22,659 | 10,090 | 13,847 | ||||||||
Expected Return on Plan Assets | -27,780 | -31,458 | -13,610 | -12,564 | ||||||||
Amortization of Transition Obligation | - | - | - | 601 | ||||||||
Amortization of Prior Service Cost (Credit) | 148 | 356 | -7,537 | -2,147 | ||||||||
Amortization of Net Actuarial Loss | 18,769 | 15,254 | 9,187 | 7,894 | ||||||||
Net Periodic Benefit Cost | $ | 16,512 | $ | 12,485 | $ | 54 | $ | 11,671 | ||||
Indiana Michigan Power Co [Member] | ||||||||||||
Components of Net Periodic Benefit Cost | I&M | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,183 | $ | 2,477 | $ | 804 | $ | 1,655 | ||||
Interest Cost | 6,025 | 6,562 | 2,056 | 3,196 | ||||||||
Expected Return on Plan Assets | -8,206 | -9,392 | -3,295 | -3,212 | ||||||||
Amortization of Transition Obligation | - | - | - | 33 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 101 | -2,356 | -595 | ||||||||
Amortization of Net Actuarial Loss | 5,422 | 4,392 | 1,882 | 1,762 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 5,473 | $ | 4,140 | $ | -909 | $ | 2,839 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 6,551 | $ | 7,431 | $ | 2,414 | $ | 4,965 | ||||
Interest Cost | 18,075 | 19,684 | 6,166 | 9,589 | ||||||||
Expected Return on Plan Assets | -24,619 | -28,175 | -9,887 | -9,635 | ||||||||
Amortization of Transition Obligation | - | - | - | 99 | ||||||||
Amortization of Prior Service Cost (Credit) | 146 | 305 | -7,066 | -1,787 | ||||||||
Amortization of Net Actuarial Loss | 16,266 | 13,177 | 5,645 | 5,287 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 16,419 | $ | 12,422 | $ | -2,728 | $ | 8,518 | ||||
Ohio Power Co [Member] | ||||||||||||
Components of Net Periodic Benefit Cost | OPCo | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,362 | $ | 2,751 | $ | 1,028 | $ | 2,187 | ||||
Interest Cost | 10,268 | 11,298 | 4,100 | 6,047 | ||||||||
Expected Return on Plan Assets | -15,103 | -17,100 | -6,221 | -5,639 | ||||||||
Amortization of Transition Obligation | - | - | - | 26 | ||||||||
Amortization of Prior Service Cost (Credit) | 71 | 186 | -3,219 | -969 | ||||||||
Amortization of Net Actuarial Loss | 9,287 | 7,610 | 3,761 | 3,418 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 6,885 | $ | 4,745 | $ | -551 | $ | 5,070 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 7,107 | $ | 8,253 | $ | 3,627 | $ | 6,561 | ||||
Interest Cost | 30,852 | 33,895 | 12,994 | 18,142 | ||||||||
Expected Return on Plan Assets | -45,386 | -51,301 | -18,698 | -16,917 | ||||||||
Amortization of Transition Obligation | - | - | - | 78 | ||||||||
Amortization of Prior Service Cost (Credit) | 212 | 557 | -9,680 | -2,905 | ||||||||
Amortization of Net Actuarial Loss | 27,905 | 22,830 | 11,843 | 10,252 | ||||||||
Net Periodic Benefit Cost | $ | 20,690 | $ | 14,234 | $ | 86 | $ | 15,211 | ||||
Public Service Co Of Oklahoma [Member] | ||||||||||||
Components of Net Periodic Benefit Cost | PSO | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,391 | $ | 1,487 | $ | 343 | $ | 709 | ||||
Interest Cost | 2,748 | 3,076 | 948 | 1,449 | ||||||||
Expected Return on Plan Assets | -3,919 | -4,503 | -1,522 | -1,480 | ||||||||
Amortization of Prior Service Cost (Credit) | 75 | -237 | -1,072 | -270 | ||||||||
Amortization of Net Actuarial Loss | 2,461 | 2,051 | 869 | 797 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,756 | $ | 1,874 | $ | -434 | $ | 1,205 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 4,172 | $ | 4,463 | $ | 1,029 | $ | 2,127 | ||||
Interest Cost | 8,245 | 9,226 | 2,844 | 4,348 | ||||||||
Expected Return on Plan Assets | -11,756 | -13,511 | -4,566 | -4,441 | ||||||||
Amortization of Prior Service Cost (Credit) | 223 | -711 | -3,217 | -809 | ||||||||
Amortization of Net Actuarial Loss | 7,383 | 6,154 | 2,607 | 2,391 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 8,267 | $ | 5,621 | $ | -1,303 | $ | 3,616 | ||||
Southwestern Electric Power Co [Member] | ||||||||||||
Components of Net Periodic Benefit Cost | SWEPCo | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended September 30, | Three Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,752 | $ | 1,775 | $ | 424 | $ | 831 | ||||
Interest Cost | 2,864 | 3,134 | 1,075 | 1,669 | ||||||||
Expected Return on Plan Assets | -4,126 | -4,717 | -1,720 | -1,699 | ||||||||
Amortization of Prior Service Cost (Credit) | 87 | -198 | -1,289 | -234 | ||||||||
Amortization of Net Actuarial Loss | 2,553 | 2,083 | 982 | 915 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 3,130 | $ | 2,077 | $ | -528 | $ | 1,482 | ||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 5,258 | $ | 5,324 | $ | 1,270 | $ | 2,493 | ||||
Interest Cost | 8,591 | 9,403 | 3,226 | 5,005 | ||||||||
Expected Return on Plan Assets | -12,381 | -14,150 | -5,160 | -5,096 | ||||||||
Amortization of Prior Service Cost (Credit) | 262 | -595 | -3,867 | -700 | ||||||||
Amortization of Net Actuarial Loss | 7,660 | 6,248 | 2,946 | 2,744 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 9,390 | $ | 6,230 | $ | -1,585 | $ | 4,446 |
Business_Segments_Tables
Business Segments (Tables) | 9 Months Ended | |||||||||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||||||||
Business Segments (Tables) [Abstract] | ||||||||||||||||||||||||||
Reportable Segment Information | Nonutility Operations | |||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Three Months Ended September 30, 2013 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 3,788 | $ | 8 | $ | 125 | $ | 251 | $ | 4 | $ | - | $ | 4,176 | ||||||||||||
Other Operating Segments | 31 | 18 | 5 | - | 3 | -57 | - | |||||||||||||||||||
Total Revenues | $ | 3,819 | $ | 26 | $ | 130 | $ | 251 | $ | 7 | $ | -57 | $ | 4,176 | ||||||||||||
Net Income (Loss) | $ | 409 | $ | 22 | $ | -1 | $ | 4 | $ | - | $ | - | $ | 434 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Three Months Ended September 30, 2012 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 3,811 | $ | 3 | $ | 142 | $ | 194 | $ | 6 | $ | - | $ | 4,156 | ||||||||||||
Other Operating Segments | 28 | 7 | 5 | - | 4 | -44 | - | |||||||||||||||||||
Total Revenues | $ | 3,839 | $ | 10 | $ | 147 | $ | 194 | $ | 10 | $ | -44 | $ | 4,156 | ||||||||||||
Net Income (Loss) | $ | 471 | $ | 14 | $ | -1 | $ | 10 | $ | -6 | $ | - | $ | 488 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Nine Months Ended September 30, 2013 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 10,520 | $ | 18 | $ | 365 | $ | 671 | $ | 10 | $ | - | $ | 11,584 | ||||||||||||
Other Operating Segments | 94 | 35 | 15 | - | 6 | -150 | - | |||||||||||||||||||
Total Revenues | $ | 10,614 | $ | 53 | $ | 380 | $ | 671 | $ | 16 | $ | -150 | $ | 11,584 | ||||||||||||
Net Income (Loss) | $ | 980 | $ | 53 | $ | -12 | $ | 15 | $ | 101 | $ | - | $ | 1,137 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | ||||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Reconciling | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | Adjustments | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Nine Months Ended September 30, 2012 | ||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||
External Customers | $ | 10,407 | $ | 5 | $ | 477 | $ | 427 | $ | 16 | $ | - | $ | 11,332 | ||||||||||||
Other Operating Segments | 75 | 10 | 16 | - | 7 | -108 | - | |||||||||||||||||||
Total Revenues | $ | 10,482 | $ | 15 | $ | 493 | $ | 427 | $ | 23 | $ | -108 | $ | 11,332 | ||||||||||||
Net Income (Loss) | $ | 1,220 | $ | 31 | $ | 11 | $ | 4 | $ | -25 | $ | - | $ | 1,241 | ||||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | Reconciling | |||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Adjustments | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | (b) | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
30-Sep-13 | ||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 56,745 | $ | 1,296 | $ | 637 | $ | 627 | $ | 8 | $ | -269 | $ | 59,044 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||
Amortization | 18,791 | 7 | 182 | 268 | 8 | -82 | 19,174 | |||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||
Equipment - Net | $ | 37,954 | $ | 1,289 | $ | 455 | $ | 359 | $ | - | $ | -187 | $ | 39,870 | ||||||||||||
Total Assets | $ | 51,598 | $ | 1,809 | $ | 650 | $ | 1,009 | $ | 17,874 | $ | -17,977 | (c) | $ | 54,963 | |||||||||||
Nonutility Operations | ||||||||||||||||||||||||||
Generation | Reconciling | |||||||||||||||||||||||||
Utility | Transmission | AEP River | and | All Other | Adjustments | |||||||||||||||||||||
Operations | Operations | Operations | Marketing | (a) | (b) | Consolidated | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
31-Dec-12 | ||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 55,707 | $ | 748 | $ | 636 | $ | 621 | $ | 8 | $ | -266 | $ | 57,454 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||
Amortization | 18,344 | 4 | 161 | 246 | 7 | -71 | 18,691 | |||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||
Equipment - Net | $ | 37,363 | $ | 744 | $ | 475 | $ | 375 | $ | 1 | $ | -195 | $ | 38,763 | ||||||||||||
Total Assets | $ | 51,477 | $ | 1,216 | $ | 670 | $ | 1,005 | $ | 17,191 | $ | -17,192 | (c) | $ | 54,367 | |||||||||||
(a) All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | ||||||||||||||||||||||||||
(b) Includes eliminations due to an intercompany capital lease. | ||||||||||||||||||||||||||
(c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. |
Derivatives_and_Hedging_Tables
Derivatives and Hedging (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
Volume | |||||||||||||||||||||
September 30, | December 31, | Unit of | |||||||||||||||||||
2013 | 2012 | Measure | |||||||||||||||||||
Primary Risk Exposure | (in millions) | ||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | 464 | 498 | MWhs | ||||||||||||||||||
Coal | 6 | 10 | Tons | ||||||||||||||||||
Natural Gas | 141 | 147 | MMBtus | ||||||||||||||||||
Heating Oil and Gasoline | 5 | 6 | Gallons | ||||||||||||||||||
Interest Rate | $ | 201 | $ | 235 | USD | ||||||||||||||||
Interest Rate and Foreign Currency | $ | 820 | $ | 1,199 | USD | ||||||||||||||||
Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Gross Amounts | Gross | Net Amounts of | |||||||||||||||||||
Risk Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in millions) | |||||||||||||||||||||
Current Risk Management Assets | $ | 441 | $ | 19 | $ | 4 | $ | 464 | $ | -293 | $ | 171 | |||||||||
Long-term Risk Management Assets | 433 | 6 | 1 | 440 | -126 | 314 | |||||||||||||||
Total Assets | 874 | 25 | 5 | 904 | -419 | 485 | |||||||||||||||
Current Risk Management Liabilities | 389 | 23 | 1 | 413 | -311 | 102 | |||||||||||||||
Long-term Risk Management Liabilities | 301 | 4 | 13 | 318 | -136 | 182 | |||||||||||||||
Total Liabilities | 690 | 27 | 14 | 731 | -447 | 284 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 184 | $ | -2 | $ | -9 | $ | 173 | $ | 28 | $ | 201 | |||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Gross Amounts | Gross | Net Amounts of | |||||||||||||||||||
Risk Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in millions) | |||||||||||||||||||||
Current Risk Management Assets | $ | 589 | $ | 32 | $ | 3 | $ | 624 | $ | -433 | $ | 191 | |||||||||
Long-term Risk Management Assets | 528 | 5 | 1 | 534 | -166 | 368 | |||||||||||||||
Total Assets | 1,117 | 37 | 4 | 1,158 | -599 | 559 | |||||||||||||||
Current Risk Management Liabilities | 546 | 43 | 35 | 624 | -469 | 155 | |||||||||||||||
Long-term Risk Management Liabilities | 383 | 6 | 6 | 395 | -181 | 214 | |||||||||||||||
Total Liabilities | 929 | 49 | 41 | 1,019 | -650 | 369 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 188 | $ | -12 | $ | -37 | $ | 139 | $ | 51 | $ | 190 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include de-designated risk management contracts. | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three and Nine Months Ended September 30, 2013 and 2012 | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Location of Gain (Loss) | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Utility Operations Revenues | $ | 4 | $ | 5 | $ | 17 | $ | 19 | |||||||||||||
Other Revenues | 9 | 20 | 39 | 28 | |||||||||||||||||
Regulatory Assets (a) | - | 2 | -3 | -35 | |||||||||||||||||
Regulatory Liabilities (a) | -5 | -14 | -10 | 12 | |||||||||||||||||
Total Gain (Loss) on Risk | |||||||||||||||||||||
Management Contracts | $ | 8 | $ | 13 | $ | 43 | $ | 24 | |||||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 9 | $ | - | $ | 9 | |||||||||||||||
Hedging Liabilities (a) | 11 | 2 | 13 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | -1 | -24 | -25 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | -2 | -4 | -6 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 24 | $ | - | $ | 24 | |||||||||||||||
Hedging Liabilities (a) | 36 | 37 | 73 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | -8 | -30 | -38 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | -8 | -4 | -12 | ||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | $ | 3 | $ | 7 | |||||||||||||||||
Amount of Collateral AEP Subsidiaries Would Have Been | |||||||||||||||||||||
Required to Post | 39 | 32 | |||||||||||||||||||
Amount Attributable to RTO and ISO Activities | 38 | 31 | |||||||||||||||||||
Liabilities Subject to Cross Default Provisions | September 30, | December 31, | |||||||||||||||||||
2013 | 2012 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual | |||||||||||||||||||||
Netting Arrangements | $ | 341 | $ | 469 | |||||||||||||||||
Amount of Cash Collateral Posted | 1 | 8 | |||||||||||||||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 258 | 328 | |||||||||||||||||||
Appalachian Power Co [Member] | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
Fair Value of Derivative Instruments | APCo | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 68,593 | $ | 233 | $ | - | $ | 68,826 | $ | -44,276 | $ | 24,550 | |||||||||
Long-term Risk Management Assets | 32,501 | 226 | - | 32,727 | -11,888 | 20,839 | |||||||||||||||
Total Assets | 101,094 | 459 | - | 101,553 | -56,164 | 45,389 | |||||||||||||||
Current Risk Management Liabilities | 59,793 | 567 | - | 60,360 | -48,719 | 11,641 | |||||||||||||||
Long-term Risk Management Liabilities | 25,003 | 15 | - | 25,018 | -12,937 | 12,081 | |||||||||||||||
Total Liabilities | 84,796 | 582 | - | 85,378 | -61,656 | 23,722 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 16,298 | $ | -123 | $ | - | $ | 16,175 | $ | 5,492 | $ | 21,667 | |||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 127,645 | $ | 338 | $ | - | $ | 127,983 | $ | -97,023 | $ | 30,960 | |||||||||
Long-term Risk Management Assets | 60,498 | 215 | - | 60,713 | -26,353 | 34,360 | |||||||||||||||
Total Assets | 188,143 | 553 | - | 188,696 | -123,376 | 65,320 | |||||||||||||||
Current Risk Management Liabilities | 119,430 | 1,182 | - | 120,612 | -103,914 | 16,698 | |||||||||||||||
Long-term Risk Management Liabilities | 47,281 | 424 | - | 47,705 | -29,229 | 18,476 | |||||||||||||||
Total Liabilities | 166,711 | 1,606 | - | 168,317 | -133,143 | 35,174 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 21,432 | $ | -1,053 | $ | - | $ | 20,379 | $ | 9,767 | $ | 30,146 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | ||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
Fair Value of Derivative Instruments | I&M | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 44,988 | $ | 149 | $ | - | $ | 45,137 | $ | -28,987 | $ | 16,150 | |||||||||
Long-term Risk Management Assets | 21,432 | 149 | - | 21,581 | -7,848 | 13,733 | |||||||||||||||
Total Assets | 66,420 | 298 | - | 66,718 | -36,835 | 29,883 | |||||||||||||||
Current Risk Management Liabilities | 40,809 | 370 | - | 41,179 | -31,911 | 9,268 | |||||||||||||||
Long-term Risk Management Liabilities | 16,836 | 7 | - | 16,843 | -8,536 | 8,307 | |||||||||||||||
Total Liabilities | 57,645 | 377 | - | 58,022 | -40,447 | 17,575 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 8,775 | $ | -79 | $ | - | $ | 8,696 | $ | 3,612 | $ | 12,308 | |||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 93,268 | $ | 220 | $ | - | $ | 93,488 | $ | -66,514 | $ | 26,974 | |||||||||
Long-term Risk Management Assets | 41,553 | 148 | - | 41,701 | -18,132 | 23,569 | |||||||||||||||
Total Assets | 134,821 | 368 | - | 135,189 | -84,646 | 50,543 | |||||||||||||||
Current Risk Management Liabilities | 82,433 | 807 | 19,524 | 102,764 | -71,247 | 31,517 | |||||||||||||||
Long-term Risk Management Liabilities | 33,714 | 292 | - | 34,006 | -20,108 | 13,898 | |||||||||||||||
Total Liabilities | 116,147 | 1,099 | 19,524 | 136,770 | -91,355 | 45,415 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 18,674 | $ | -731 | $ | -19,524 | $ | -1,581 | $ | 6,709 | $ | 5,128 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | ||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Ohio Power Co [Member] | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
Fair Value of Derivative Instruments | OPCo | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 96,628 | $ | 315 | $ | - | $ | 96,943 | $ | -62,765 | $ | 34,178 | |||||||||
Long-term Risk Management Assets | 44,597 | 310 | - | 44,907 | -16,313 | 28,594 | |||||||||||||||
Total Assets | 141,225 | 625 | - | 141,850 | -79,078 | 62,772 | |||||||||||||||
Current Risk Management Liabilities | 84,519 | 774 | - | 85,293 | -68,862 | 16,431 | |||||||||||||||
Long-term Risk Management Liabilities | 34,309 | 18 | - | 34,327 | -17,750 | 16,577 | |||||||||||||||
Total Liabilities | 118,828 | 792 | - | 119,620 | -86,612 | 33,008 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 22,397 | $ | -167 | $ | - | $ | 22,230 | $ | 7,534 | $ | 29,764 | |||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 183,064 | $ | 464 | $ | - | $ | 183,528 | $ | -139,215 | $ | 44,313 | |||||||||
Long-term Risk Management Assets | 85,023 | 303 | - | 85,326 | -37,038 | 48,288 | |||||||||||||||
Total Assets | 268,087 | 767 | - | 268,854 | -176,253 | 92,601 | |||||||||||||||
Current Risk Management Liabilities | 171,397 | 1,658 | - | 173,055 | -148,900 | 24,155 | |||||||||||||||
Long-term Risk Management Liabilities | 66,448 | 596 | - | 67,044 | -41,079 | 25,965 | |||||||||||||||
Total Liabilities | 237,845 | 2,254 | - | 240,099 | -189,979 | 50,120 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 30,242 | $ | -1,487 | $ | - | $ | 28,755 | $ | 13,726 | $ | 42,481 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | ||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
Fair Value of Derivative Instruments | PSO | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,394 | $ | 13 | $ | - | $ | 1,407 | $ | -555 | $ | 852 | |||||||||
Long-term Risk Management Assets | 149 | - | - | 149 | - | 149 | |||||||||||||||
Total Assets | 1,543 | 13 | - | 1,556 | -555 | 1,001 | |||||||||||||||
Current Risk Management Liabilities | 1,931 | 12 | - | 1,943 | -555 | 1,388 | |||||||||||||||
Long-term Risk Management Liabilities | - | 7 | - | 7 | -7 | - | |||||||||||||||
Total Liabilities | 1,931 | 19 | - | 1,950 | -562 | 1,388 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -388 | $ | -6 | $ | - | $ | -394 | $ | 7 | $ | -387 | |||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,657 | $ | 42 | $ | - | $ | 1,699 | $ | -1,190 | $ | 509 | |||||||||
Long-term Risk Management Assets | - | - | - | - | 31 | 31 | |||||||||||||||
Total Assets | 1,657 | 42 | - | 1,699 | -1,159 | 540 | |||||||||||||||
Current Risk Management Liabilities | 7,021 | 17 | - | 7,038 | -1,190 | 5,848 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | 31 | 31 | |||||||||||||||
Total Liabilities | 7,021 | 17 | - | 7,038 | -1,159 | 5,879 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -5,364 | $ | 25 | $ | - | $ | -5,339 | $ | - | $ | -5,339 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | ||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||||||||
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 75,861 | 49,918 | 104,093 | 8 | 10 | |||||||||||||||
Coal | Tons | 282 | 3,980 | 813 | 2,075 | 1,229 | |||||||||||||||
Natural Gas | MMBtus | 4,121 | 2,711 | 5,654 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 981 | 484 | 1,155 | 491 | 603 | |||||||||||||||
Interest Rate | USD | $ | 16,501 | $ | 10,858 | $ | 22,642 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 94,059 | 64,791 | 132,188 | - | - | |||||||||||||||
Coal | Tons | 1,401 | 2,711 | 3,033 | 1,980 | 1,312 | |||||||||||||||
Natural Gas | MMBtus | 10,077 | 6,922 | 14,163 | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,050 | 532 | 1,260 | 616 | 585 | |||||||||||||||
Interest Rate | USD | $ | 24,146 | $ | 16,584 | $ | 33,934 | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | 200,000 | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Cash Collateral | Cash Collateral | Cash Collateral | Cash Collateral | ||||||||||||||||||
Received | Paid | Received | Paid | ||||||||||||||||||
Netted Against | Netted Against | Netted Against | Netted Against | ||||||||||||||||||
Risk Management | Risk Management | Risk Management | Risk Management | ||||||||||||||||||
Company | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 116 | $ | 5,608 | $ | 1,262 | $ | 11,029 | |||||||||||||
I&M | 76 | 3,688 | 867 | 7,576 | |||||||||||||||||
OPCo | 159 | 7,693 | 1,774 | 15,500 | |||||||||||||||||
PSO | - | 7 | - | - | |||||||||||||||||
SWEPCo | - | 8 | - | - | |||||||||||||||||
Fair Value of Derivative Instruments | SWEPCo | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 1,444 | $ | 15 | $ | - | $ | 1,459 | $ | -1,057 | $ | 402 | |||||||||
Long-term Risk Management Assets | 21 | - | - | 21 | - | 21 | |||||||||||||||
Total Assets | 1,465 | 15 | - | 1,480 | -1,057 | 423 | |||||||||||||||
Current Risk Management Liabilities | 1,339 | 14 | - | 1,353 | -1,057 | 296 | |||||||||||||||
Long-term Risk Management Liabilities | - | 8 | - | 8 | -8 | - | |||||||||||||||
Total Liabilities | 1,339 | 22 | - | 1,361 | -1,065 | 296 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 126 | $ | -7 | $ | - | $ | 119 | $ | 8 | $ | 127 | |||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Risk | Gross Amounts | Gross | Net Amounts of | ||||||||||||||||||
Management | of Risk | Amounts | Assets/Liabilities | ||||||||||||||||||
Contracts | Hedging Contracts | Management | Offset in the | Presented in the | |||||||||||||||||
Interest Rate | Assets/ | Statement of | Statement of | ||||||||||||||||||
and Foreign | Liabilities | Financial | Financial | ||||||||||||||||||
Balance Sheet Location | Commodity (a) | Commodity (a) | Currency (a) | Recognized | Position (b) | Position (c) | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Current Risk Management Assets | $ | 2,804 | $ | 41 | $ | - | $ | 2,845 | $ | -2,150 | $ | 695 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 2,804 | 41 | - | 2,845 | -2,150 | 695 | |||||||||||||||
Current Risk Management Liabilities | 3,261 | 17 | - | 3,278 | -2,150 | 1,128 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 3,261 | 17 | - | 3,278 | -2,150 | 1,128 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | -457 | $ | 24 | $ | - | $ | -433 | $ | - | $ | -433 | |||||||||
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||||||||||||||
(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||||||||||||||
Amount of Gain Loss Recognized on Risk Management Contracts | Amount of Gain (Loss) Recognized on | ||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 746 | $ | 1,742 | $ | 66 | $ | 25 | $ | 51 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,349 | - | 960 | 421 | ||||||||||||||||
Regulatory Liabilities (a) | -950 | -2,347 | -1,264 | 18 | 130 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -204 | $ | -1,954 | $ | -1,198 | $ | 1,003 | $ | 602 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 378 | $ | 3,814 | $ | 87 | $ | 71 | $ | 174 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -138 | -1,213 | 3,000 | 598 | 115 | ||||||||||||||||
Regulatory Liabilities (a) | -1,672 | -5,267 | -6,788 | 2 | 11 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | -1,432 | $ | -2,666 | $ | -3,701 | $ | 671 | $ | 300 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 1,619 | $ | 9,586 | $ | 3,599 | $ | 241 | $ | 381 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | - | -1,648 | -5,158 | 3,162 | 427 | ||||||||||||||||
Regulatory Liabilities (a) | -1,160 | -9,209 | 1,557 | 18 | 157 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 459 | $ | -1,271 | $ | -2 | $ | 3,421 | $ | 965 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Nine Months Ended September 30, 2012 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | -548 | $ | 9,206 | $ | 11,118 | $ | 231 | $ | 426 | |||||||||||
Sales to AEP Affiliates | - | - | - | - | - | ||||||||||||||||
Fuel and Other Consumables Used for | |||||||||||||||||||||
Electric Generation | - | - | - | - | - | ||||||||||||||||
Regulatory Assets (a) | -6,133 | -7,228 | -9,026 | -5,360 | -6,977 | ||||||||||||||||
Regulatory Liabilities (a) | 8,166 | 1,851 | 390 | 3 | 6 | ||||||||||||||||
Total Gain (Loss) on Risk Management | |||||||||||||||||||||
Contracts | $ | 1,485 | $ | 3,829 | $ | 2,482 | $ | -5,126 | $ | -6,545 | |||||||||||
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current | |||||||||||||||||||||
or noncurrent on the condensed balance sheets. | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | ||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 307 | $ | - | $ | 430 | $ | - | $ | -34 | $ | 2,836 | |||||||||
I&M | 199 | - | 278 | - | -19 | -16,386 | |||||||||||||||
OPCo | 418 | - | 585 | - | -47 | 7,076 | |||||||||||||||
PSO | 10 | - | 16 | - | -3 | 5,891 | |||||||||||||||
SWEPCo | 12 | - | 19 | - | -3 | -13,871 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Maximum Term for | |||||||||||||||||||||
Interest Rate | Exposure to | ||||||||||||||||||||
and Foreign | Variability of Future | ||||||||||||||||||||
Company | Commodity | Currency | Cash Flows | ||||||||||||||||||
(in thousands) | (in months) | ||||||||||||||||||||
APCo | $ | -172 | $ | -930 | 15 | ||||||||||||||||
I&M | -113 | -1,640 | 15 | ||||||||||||||||||
OPCo | -236 | 1,359 | 15 | ||||||||||||||||||
PSO | 1 | 759 | 15 | ||||||||||||||||||
SWEPCo | 1 | -2,267 | 15 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Hedging Assets (a) | Hedging Liabilities (a) | AOCI Gain (Loss) Net of Tax | |||||||||||||||||||
Interest Rate | Interest Rate | Interest Rate | |||||||||||||||||||
and Foreign | and Foreign | and Foreign | |||||||||||||||||||
Company | Commodity | Currency | Commodity | Currency | Commodity | Currency | |||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 302 | $ | - | $ | 1,355 | $ | - | $ | -644 | $ | 2,077 | |||||||||
I&M | 200 | - | 931 | 19,524 | -446 | -19,647 | |||||||||||||||
OPCo | 416 | - | 1,903 | - | -912 | 8,095 | |||||||||||||||
PSO | 25 | - | - | - | 21 | 6,460 | |||||||||||||||
SWEPCo | 24 | - | - | - | 22 | -15,571 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | -507 | $ | -1,013 | |||||||||||||||||
I&M | -355 | -1,600 | |||||||||||||||||||
OPCo | -720 | 1,359 | |||||||||||||||||||
PSO | 21 | 759 | |||||||||||||||||||
SWEPCo | 22 | -2,267 | |||||||||||||||||||
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||||||||||||||
Collateral Required Under Various Triggering Events | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 850 | $ | 6,183 | $ | 5,812 | |||||||||||||||
I&M | 560 | 4,069 | 3,824 | ||||||||||||||||||
OPCo | 1,167 | 8,484 | 7,975 | ||||||||||||||||||
PSO | - | 255 | 200 | ||||||||||||||||||
SWEPCo | - | 315 | 247 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Amount of Collateral the | Amount | |||||||||||||||||||
Derivative Contracts | Registrant Subsidiaries | Attributable to | |||||||||||||||||||
with Credit | Would Have Been | RTO and ISO | |||||||||||||||||||
Company | Downgrade Triggers | Required to Post | Activities | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 2,159 | $ | 3,699 | $ | 3,510 | |||||||||||||||
I&M | 1,483 | 2,540 | 2,411 | ||||||||||||||||||
OPCo | 3,034 | 5,198 | 4,933 | ||||||||||||||||||
PSO | - | 1,509 | 1,429 | ||||||||||||||||||
SWEPCo | - | 1,778 | 1,683 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | 30-Sep-13 | ||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 27,044 | $ | - | $ | 22,162 | |||||||||||||||
I&M | 17,796 | - | 14,583 | ||||||||||||||||||
OPCo | 37,110 | - | 30,410 | ||||||||||||||||||
PSO | 5 | - | 5 | ||||||||||||||||||
SWEPCo | 6 | - | 6 | ||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Liabilities for | Additional | ||||||||||||||||||||
Contracts with Cross | Settlement | ||||||||||||||||||||
Default Provisions | Liability if Cross | ||||||||||||||||||||
Prior to Contractual | Amount of Cash | Default Provision | |||||||||||||||||||
Company | Netting Arrangements | Collateral Posted | is Triggered | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 49,465 | $ | 1,822 | $ | 30,160 | |||||||||||||||
I&M | 53,499 | 1,252 | 40,240 | ||||||||||||||||||
OPCo | 69,516 | 2,561 | 42,386 | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Book Value | Fair Value | Book Value | Fair Value | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Long-term Debt | $ | 17,568 | $ | 19,316 | $ | 17,757 | $ | 20,907 | |||||||||||||
Other Temporary Investments | 30-Sep-13 | ||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 188 | $ | - | $ | - | $ | 188 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 79 | - | - | 79 | |||||||||||||||||
Equity Securities - Mutual Funds | 13 | 8 | - | 21 | |||||||||||||||||
Total Other Temporary Investments | $ | 280 | $ | 8 | $ | - | $ | 288 | |||||||||||||
31-Dec-12 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 241 | $ | - | $ | - | $ | 241 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 65 | 2 | - | 67 | |||||||||||||||||
Equity Securities - Mutual Funds | 10 | 6 | - | 16 | |||||||||||||||||
Total Other Temporary Investments | $ | 316 | $ | 8 | $ | - | $ | 324 | |||||||||||||
(a) | Primarily represents amounts held for the repayment of debt. | ||||||||||||||||||||
Debt and Equity Securities Within Other Temporary Investments | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | - | $ | - | $ | - | $ | - | |||||||||||||
Purchases of Investments | 6 | - | 17 | 1 | |||||||||||||||||
Gross Realized Gains on Investment Sales | - | - | - | - | |||||||||||||||||
Gross Realized Losses on Investment Sales | - | - | - | - | |||||||||||||||||
Nuclear Trust Fund Investments | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Estimated | Gross | Other-Than- | Estimated | Gross | Other-Than- | ||||||||||||||||
Fair | Unrealized | Temporary | Fair | Unrealized | Temporary | ||||||||||||||||
Value | Gains | Impairments | Value | Gains | Impairments | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Cash and Cash Equivalents | $ | 15 | $ | - | $ | - | $ | 17 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 621 | 34 | -3 | 648 | 58 | -1 | |||||||||||||||
Corporate Debt | 38 | 2 | -2 | 35 | 5 | -1 | |||||||||||||||
State and Local Government | 244 | 1 | - | 270 | 1 | -1 | |||||||||||||||
Subtotal Fixed Income Securities | 903 | 37 | -5 | 953 | 64 | -3 | |||||||||||||||
Equity Securities - Domestic | 921 | 415 | -81 | 736 | 285 | -77 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,839 | $ | 452 | $ | -86 | $ | 1,706 | $ | 349 | $ | -80 | |||||||||
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 250 | $ | 182 | $ | 635 | $ | 699 | |||||||||||||
Purchases of Investments | 264 | 199 | 676 | 744 | |||||||||||||||||
Gross Realized Gains on Investment Sales | 4 | 2 | 16 | 7 | |||||||||||||||||
Gross Realized Losses on Investment Sales | 2 | 1 | 12 | 3 | |||||||||||||||||
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of | ||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Within 1 year | $ | 74 | |||||||||||||||||||
1 year – 5 years | 378 | ||||||||||||||||||||
5 years – 10 years | 210 | ||||||||||||||||||||
After 10 years | 241 | ||||||||||||||||||||
Total | $ | 903 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | Assets and Liabilities Measured at Fair Value on a Recurring Basis | ||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 14 | $ | 1 | $ | - | $ | 132 | $ | 147 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 173 | 7 | - | 8 | 188 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 79 | - | - | - | 79 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 21 | - | - | - | 21 | ||||||||||||||||
Total Other Temporary Investments | 273 | 7 | - | 8 | 288 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | 34 | 680 | 147 | -399 | 462 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | 2 | 22 | - | -15 | 9 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 3 | 5 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 9 | 9 | ||||||||||||||||
Total Risk Management Assets | 36 | 704 | 147 | -402 | 485 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 6 | - | - | 9 | 15 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 621 | - | - | 621 | ||||||||||||||||
Corporate Debt | - | 38 | - | - | 38 | ||||||||||||||||
State and Local Government | - | 244 | - | - | 244 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 903 | - | - | 903 | ||||||||||||||||
Equity Securities - Domestic (b) | 921 | - | - | - | 921 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 927 | 903 | - | 9 | 1,839 | ||||||||||||||||
Total Assets | $ | 1,250 | $ | 1,615 | $ | 147 | $ | -253 | $ | 2,759 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | $ | 40 | $ | 613 | $ | 24 | $ | -418 | $ | 259 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 23 | 3 | -15 | 11 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 9 | - | 3 | 12 | ||||||||||||||||
Total Risk Management Liabilities | $ | 40 | $ | 647 | $ | 27 | $ | -430 | $ | 284 | |||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 6 | $ | 1 | $ | - | $ | 272 | $ | 279 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 227 | 5 | - | 9 | 241 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 67 | - | - | - | 67 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 16 | - | - | - | 16 | ||||||||||||||||
Total Other Temporary Investments | 310 | 5 | - | 9 | 324 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | 47 | 938 | 131 | -599 | 517 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | 8 | 28 | - | -12 | 24 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 14 | 14 | ||||||||||||||||
Total Risk Management Assets | 55 | 968 | 131 | -595 | 559 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 7 | - | - | 10 | 17 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 648 | - | - | 648 | ||||||||||||||||
Corporate Debt | - | 35 | - | - | 35 | ||||||||||||||||
State and Local Government | - | 270 | - | - | 270 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 953 | - | - | 953 | ||||||||||||||||
Equity Securities - Domestic (b) | 736 | - | - | - | 736 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 743 | 953 | - | 10 | 1,706 | ||||||||||||||||
Total Assets | $ | 1,114 | $ | 1,927 | $ | 131 | $ | -304 | $ | 2,868 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | $ | 45 | $ | 838 | $ | 45 | $ | -636 | $ | 292 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 48 | - | -12 | 36 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 37 | - | - | 37 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
Total Risk Management Liabilities | $ | 45 | $ | 925 | $ | 45 | $ | -646 | $ | 369 | |||||||||||
(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(b) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(c) 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.'' | |||||||||||||||||||||
(d) The September 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $1 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $4 million in 2013, $48 million in periods 2014-2016, $8 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $6 million in 2013, $60 million in periods 2014-2016, $32 million in periods 2017-2018 and $25 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||||||||||||||
(e) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts. | |||||||||||||||||||||
(f) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(g) The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | Net Risk Management | ||||||||||||||||||||
Three Months Ended September 30, 2013 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 122 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -2 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 13 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | -3 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -8 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | - | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -2 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | - | ||||||||||||||||||||
Balance as of September 30, 2013 | $ | 120 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Three Months Ended September 30, 2012 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 97 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -5 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 7 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 5 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | 4 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | -3 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -1 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | - | ||||||||||||||||||||
Balance as of September 30, 2012 | $ | 104 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Nine Months Ended September 30, 2013 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 86 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -9 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 32 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | -3 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -7 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 18 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -1 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 4 | ||||||||||||||||||||
Balance as of September 30, 2013 | $ | 120 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Nine Months Ended September 30, 2012 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 69 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | -16 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | 20 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 2 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | 33 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 10 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -21 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 7 | ||||||||||||||||||||
Balance as of September 30, 2012 | $ | 104 | |||||||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
Significant Unobservable Inputs for Level 3 | Fair Value | Valuation | Significant | Input/Range | |||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 139 | $ | 23 | Discounted Cash Flow | Forward Market Price (a) | $ | 10.86 | $ | 126.65 | |||||||||||
Counterparty Credit Risk (b) | 374 | ||||||||||||||||||||
FTRs | 8 | 4 | Discounted Cash Flow | Forward Market Price (a) | -11.44 | 13.11 | |||||||||||||||
Total | $ | 147 | $ | 27 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
(b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. | |||||||||||||||||||||
Appalachian Power Co [Member] | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | APCo | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,799 | $ | 85,442 | $ | 13,701 | $ | -55,860 | $ | 45,082 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 452 | - | -145 | 307 | ||||||||||||||||
Total Risk Management Assets | $ | 1,799 | $ | 85,894 | $ | 13,701 | $ | -56,005 | $ | 45,389 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,274 | $ | 80,580 | $ | 2,790 | $ | -61,352 | $ | 23,292 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 575 | - | -145 | 430 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,274 | $ | 81,155 | $ | 2,790 | $ | -61,497 | $ | 23,722 | |||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 4,161 | $ | 166,916 | $ | 17,058 | $ | -123,117 | $ | 65,018 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 498 | - | -196 | 302 | ||||||||||||||||
Total Risk Management Assets | $ | 4,161 | $ | 167,414 | $ | 17,058 | $ | -123,313 | $ | 65,320 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,959 | $ | 158,665 | $ | 6,079 | $ | -132,884 | $ | 33,819 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 1,551 | - | -196 | 1,355 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,959 | $ | 160,216 | $ | 6,079 | $ | -133,080 | $ | 35,174 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2013 | APCo | I&M | OPCo | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
Significant Unobservable Inputs for Level 3 | APCo | ||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 11,506 | $ | 1,940 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 2,195 | 850 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 13,701 | $ | 2,790 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Indiana Michigan Power Co [Member] | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Nuclear Trust Fund Investments | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Estimated | Gross | Other-Than- | Estimated | Gross | Other-Than- | ||||||||||||||||
Fair | Unrealized | Temporary | Fair | Unrealized | Temporary | ||||||||||||||||
Value | Gains | Impairments | Value | Gains | Impairments | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Cash and Cash Equivalents | $ | 14,438 | $ | - | $ | - | $ | 16,783 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 620,944 | 34,377 | -2,662 | 647,918 | 58,268 | -747 | |||||||||||||||
Corporate Debt | 38,272 | 2,684 | -1,786 | 35,399 | 4,903 | -1,352 | |||||||||||||||
State and Local Government | 244,172 | 851 | -358 | 270,090 | 1,006 | -863 | |||||||||||||||
Subtotal Fixed Income Securities | 903,388 | 37,912 | -4,806 | 953,407 | 64,177 | -2,962 | |||||||||||||||
Equity Securities - Domestic | 921,292 | 414,931 | -81,125 | 735,582 | 284,599 | -76,557 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,839,118 | $ | 452,843 | $ | -85,931 | $ | 1,705,772 | $ | 348,776 | $ | -79,519 | |||||||||
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 249,314 | $ | 181,988 | $ | 635,256 | $ | 698,567 | |||||||||||||
Purchases of Investments | 263,958 | 199,150 | 675,727 | 744,131 | |||||||||||||||||
Gross Realized Gains on Investment Sales | 4,113 | 2,046 | 16,011 | 6,978 | |||||||||||||||||
Gross Realized Losses on Investment Sales | 2,147 | 924 | 11,859 | 3,143 | |||||||||||||||||
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of | ||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Within 1 year | $ | 73,908 | |||||||||||||||||||
1 year – 5 years | 378,271 | ||||||||||||||||||||
5 years – 10 years | 210,201 | ||||||||||||||||||||
After 10 years | 241,008 | ||||||||||||||||||||
Total | $ | 903,388 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | I&M | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,184 | $ | 56,155 | $ | 9,015 | $ | -36,670 | $ | 29,684 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 294 | - | -95 | 199 | ||||||||||||||||
Total Risk Management Assets | 1,184 | 56,449 | 9,015 | -36,765 | 29,883 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (c) | 5,684 | - | - | 8,754 | 14,438 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 620,944 | - | - | 620,944 | ||||||||||||||||
Corporate Debt | - | 38,272 | - | - | 38,272 | ||||||||||||||||
State and Local Government | - | 244,172 | - | - | 244,172 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 903,388 | - | - | 903,388 | ||||||||||||||||
Equity Securities - Domestic (d) | 921,292 | - | - | - | 921,292 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 926,976 | 903,388 | - | 8,754 | 1,839,118 | ||||||||||||||||
Total Assets | $ | 928,160 | $ | 959,837 | $ | 9,015 | $ | -28,011 | $ | 1,869,001 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 838 | $ | 54,905 | $ | 1,836 | $ | -40,282 | $ | 17,297 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 373 | - | -95 | 278 | ||||||||||||||||
Total Risk Management Liabilities | $ | 838 | $ | 55,278 | $ | 1,836 | $ | -40,377 | $ | 17,575 | |||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 2,858 | $ | 120,242 | $ | 11,717 | $ | -84,474 | $ | 50,343 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 330 | - | -130 | 200 | ||||||||||||||||
Total Risk Management Assets | 2,858 | 120,572 | 11,717 | -84,604 | 50,543 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (c) | 6,508 | - | - | 10,275 | 16,783 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 647,918 | - | - | 647,918 | ||||||||||||||||
Corporate Debt | - | 35,399 | - | - | 35,399 | ||||||||||||||||
State and Local Government | - | 270,090 | - | - | 270,090 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 953,407 | - | - | 953,407 | ||||||||||||||||
Equity Securities - Domestic (d) | 735,582 | - | - | - | 735,582 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 742,090 | 953,407 | - | 10,275 | 1,705,772 | ||||||||||||||||
Total Assets | $ | 744,948 | $ | 1,073,979 | $ | 11,717 | $ | -74,329 | $ | 1,756,315 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,346 | $ | 110,621 | $ | 4,176 | $ | -91,183 | $ | 24,960 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 1,061 | - | -130 | 931 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 19,524 | - | - | 19,524 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,346 | $ | 131,206 | $ | 4,176 | $ | -91,313 | $ | 45,415 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2013 | APCo | I&M | OPCo | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
Significant Unobservable Inputs for Level 3 | I&M | ||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 7,571 | $ | 1,276 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 1,444 | 560 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 9,015 | $ | 1,836 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Ohio Power Co [Member] | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | OPCo | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Other Cash Deposits (e) | $ | 8,022 | $ | 26 | $ | - | $ | 17 | $ | 8,065 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | 2,469 | 119,749 | 18,799 | -78,663 | 62,354 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 616 | - | -198 | 418 | ||||||||||||||||
Total Risk Management Assets | 2,469 | 120,365 | 18,799 | -78,861 | 62,772 | ||||||||||||||||
Total Assets | $ | 10,491 | $ | 120,391 | $ | 18,799 | $ | -78,844 | $ | 70,837 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 1,748 | $ | 113,044 | $ | 3,828 | $ | -86,197 | $ | 32,423 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 783 | - | -198 | 585 | ||||||||||||||||
Total Risk Management Liabilities | $ | 1,748 | $ | 113,827 | $ | 3,828 | $ | -86,395 | $ | 33,008 | |||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Other Cash Deposits (e) | $ | - | $ | 26 | $ | - | $ | 39 | $ | 65 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | 5,848 | 238,254 | 23,973 | -175,890 | 92,185 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 688 | - | -272 | 416 | ||||||||||||||||
Total Risk Management Assets | 5,848 | 238,942 | 23,973 | -176,162 | 92,601 | ||||||||||||||||
Total Assets | $ | 5,848 | $ | 238,968 | $ | 23,973 | $ | -176,123 | $ | 92,666 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | 2,753 | $ | 226,536 | $ | 8,544 | $ | -189,616 | $ | 48,217 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 2,175 | - | -272 | 1,903 | ||||||||||||||||
Total Risk Management Liabilities | $ | 2,753 | $ | 228,711 | $ | 8,544 | $ | -189,888 | $ | 50,120 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended September 30, 2013 | APCo | I&M | OPCo | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2013 | $ | 12,976 | $ | 8,967 | $ | 18,347 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -1,200 | -754 | -1,616 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -89 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | -1,058 | -757 | -1,504 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 13 | 9 | 18 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -15 | -11 | -21 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 195 | -275 | -164 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Three Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of June 30, 2012 | $ | 12,864 | $ | 9,049 | $ | 18,969 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,540 | -2,440 | -5,024 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,030 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 403 | 277 | 571 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 929 | 635 | 1,299 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 654 | 460 | 964 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -287 | -202 | -423 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 17 | -193 | 253 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
Nine Months Ended September 30, 2013 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2012 | $ | 10,979 | $ | 7,541 | $ | 15,429 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -3,450 | -2,386 | -4,879 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 351 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 1,712 | 1,213 | 2,463 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 961 | 661 | 1,353 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -925 | -637 | -1,303 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 1,634 | 787 | 1,557 | ||||||||||||||||||
Balance as of September 30, 2013 | $ | 10,911 | $ | 7,179 | $ | 14,971 | |||||||||||||||
Nine Months Ended September 30, 2012 | APCo | I&M | OPCo | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2011 | $ | 1,971 | $ | 1,263 | $ | 2,666 | |||||||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | -5,108 | -3,488 | -7,316 | ||||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | 4,973 | ||||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | 312 | 211 | 435 | ||||||||||||||||||
Purchases, Issuances and Settlements (c) | 10,605 | 7,325 | 15,375 | ||||||||||||||||||
Transfers into Level 3 (d) (e) | 4,142 | 2,749 | 5,789 | ||||||||||||||||||
Transfers out of Level 3 (e) (f) | -4,910 | -3,193 | -6,733 | ||||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 4,028 | 2,719 | 390 | ||||||||||||||||||
Balance as of September 30, 2012 | $ | 11,040 | $ | 7,586 | $ | 15,579 | |||||||||||||||
(a) Included in revenues on the condensed statements of income. | |||||||||||||||||||||
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||||||||||||||
(c) Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||||||||||||||
(d) Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||||||||||||||
(e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||||||||||||||
(f) Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||||||||||||||
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||||||||||||||
Significant Unobservable Inputs for Level 3 | OPCo | ||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 15,787 | $ | 2,661 | Discounted Cash Flow | Forward Market Price | $ | 12.52 | $ | 55.4 | |||||||||||
FTRs | 3,012 | 1,167 | Discounted Cash Flow | Forward Market Price | -5.26 | 10.85 | |||||||||||||||
Total | $ | 18,799 | $ | 3,828 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | PSO | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,543 | $ | - | $ | -552 | $ | 991 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 10 | - | - | 10 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,553 | $ | - | $ | -552 | $ | 1,001 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,931 | $ | - | $ | -559 | $ | 1,372 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 16 | - | - | 16 | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 1,947 | $ | - | $ | -559 | $ | 1,388 | |||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,657 | $ | - | $ | -1,142 | $ | 515 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 42 | - | -17 | 25 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,699 | $ | - | $ | -1,159 | $ | 540 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 7,021 | $ | - | $ | -1,142 | $ | 5,879 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 17 | - | -17 | - | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 7,038 | $ | - | $ | -1,159 | $ | 5,879 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
Southwestern Electric Power Co [Member] | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 3,427,917 | $ | 3,957,321 | $ | 3,702,442 | $ | 4,555,143 | |||||||||||||
I&M | 2,271,613 | 2,461,671 | 2,057,666 | 2,372,017 | |||||||||||||||||
OPCo | 3,698,574 | 4,071,613 | 3,860,440 | 4,560,337 | |||||||||||||||||
PSO | 949,826 | 1,090,934 | 949,871 | 1,175,759 | |||||||||||||||||
SWEPCo | 2,043,244 | 2,254,078 | 2,046,228 | 2,400,509 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | SWEPCo | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (e) | $ | 14,186 | $ | - | $ | - | $ | 3,465 | $ | 17,651 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | - | 1,464 | - | -1,053 | 411 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 12 | - | - | 12 | ||||||||||||||||
Total Risk Management Assets | - | 1,476 | - | -1,053 | 423 | ||||||||||||||||
Total Assets | $ | 14,186 | $ | 1,476 | $ | - | $ | 2,412 | $ | 18,074 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 1,338 | $ | - | $ | -1,061 | $ | 277 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 19 | - | - | 19 | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 1,357 | $ | - | $ | -1,061 | $ | 296 | |||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 2,804 | $ | - | $ | -2,133 | $ | 671 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 41 | - | -17 | 24 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 2,845 | $ | - | $ | -2,150 | $ | 695 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (a) (b) | $ | - | $ | 3,261 | $ | - | $ | -2,133 | $ | 1,128 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (a) | - | 17 | - | -17 | - | ||||||||||||||||
Total Risk Management Liabilities | $ | - | $ | 3,278 | $ | - | $ | -2,150 | $ | 1,128 | |||||||||||
(a) 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.” | |||||||||||||||||||||
(b) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(c) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(d) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
(e) Amounts in “Other” column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. |
Financing_Activities_Tables
Financing Activities (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Long-term Debt | Type of Debt | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||
(in millions) | ||||||||||||||||||||
Senior Unsecured Notes | $ | 11,705 | $ | 12,712 | ||||||||||||||||
Pollution Control Bonds | 1,982 | 1,958 | ||||||||||||||||||
Notes Payable | 425 | 427 | ||||||||||||||||||
Securitization Bonds | 2,338 | 2,281 | ||||||||||||||||||
Spent Nuclear Fuel Obligation (a) | 265 | 265 | ||||||||||||||||||
Other Long-term Debt | 886 | 140 | ||||||||||||||||||
Fair Value of Interest Rate Hedges | -7 | 3 | ||||||||||||||||||
Unamortized Discount, Net | -26 | -29 | ||||||||||||||||||
Total Long-term Debt Outstanding | 17,568 | 17,757 | ||||||||||||||||||
Long-term Debt Due Within One Year | 1,366 | 2,171 | ||||||||||||||||||
Long-term Debt | $ | 16,202 | $ | 15,586 | ||||||||||||||||
(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $308 million as of September 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets. | ||||||||||||||||||||
Long-term Debt Issuances | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount | Rate | Due Date | ||||||||||||||||
Issuances: | (in millions) | (%) | ||||||||||||||||||
AEP | Other Long-term Debt | $ | 200 | (a) | Variable | 2015 | ||||||||||||||
APCo | Pollution Control Bonds | 30 | 3.25 | 2018 | ||||||||||||||||
APCo | Pollution Control Bonds | 40 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 600 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 165 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102 | 2.05 | 2020 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEPTCo | Senior Unsecured Notes | 25 | 4.83 | 2043 | ||||||||||||||||
TCC | Other Long-term Debt | 75 | (c) | Variable | 2016 | |||||||||||||||
TCC | Pollution Control Bonds | 120 | 4 | 2030 | ||||||||||||||||
TNC | Other Long-term Debt | 75 | (d) | Variable | 2016 | |||||||||||||||
TNC | Senior Unsecured Notes | 125 | 3.09 | 2023 | ||||||||||||||||
TNC | Senior Unsecured Notes | 75 | 4.48 | 2043 | ||||||||||||||||
Total Issuances | $ | 2,098 | (e) | |||||||||||||||||
(a) Draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(b) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
(c) Draw on a $100 million three-year revolving credit facility to be used for general corporate purposes. | ||||||||||||||||||||
(d) Draw on a $75 million three-year revolving credit facility to be used for general corporate purposes. | ||||||||||||||||||||
(e) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances. | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in millions) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
AEP | Other Long-term Debt | $ | 200 | (a) | Variable | 2015 | ||||||||||||||
APCo | Pollution Control Bonds | 30 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 10 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 15 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 4 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 1 | 6 | 2025 | ||||||||||||||||
I&M | Pollution Control Bonds | 40 | 5.25 | 2025 | ||||||||||||||||
OPCo | Pollution Control Bonds | 56 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225 | 6.38 | 2033 | ||||||||||||||||
SWEPCo | Notes Payable | 3 | 4.58 | 2032 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEP Subsidiaries | Notes Payable | 5 | Variable | 2017 | ||||||||||||||||
AEP Subsidiaries | Notes Payable | 2 | 7.59 - 8.03 | 2026 | ||||||||||||||||
AEGCo | Senior Unsecured Notes | 7 | 6.33 | 2037 | ||||||||||||||||
TCC | Securitization Bonds | 76 | 4.98 | 2013 | ||||||||||||||||
TCC | Securitization Bonds | 67 | 5.96 | 2013 | ||||||||||||||||
TCC | Securitization Bonds | 42 | 5.09 | 2015 | ||||||||||||||||
TCC | Securitization Bonds | 26 | 0.88 | 2017 | ||||||||||||||||
TNC | Senior Unsecured Notes | 225 | 5.5 | 2013 | ||||||||||||||||
Total Retirements and | ||||||||||||||||||||
Principal Payments | $ | 2,281 | ||||||||||||||||||
(a) Draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Short Term Debt | 30-Sep-13 | 31-Dec-12 | ||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Type of Debt | Amount | Rate (a) | Amount | Rate (a) | ||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||
Securitized Debt for Receivables (b) | $ | 700 | 0.23 | % | $ | 657 | 0.26 | % | ||||||||||||
Commercial Paper | 518 | 0.31 | % | 321 | 0.42 | % | ||||||||||||||
Line of Credit – Sabine (c) | - | - | % | 3 | 1.82 | % | ||||||||||||||
Total Short-term Debt | $ | 1,218 | $ | 981 | ||||||||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | ||||||||||||||||||||
(c) This line of credit does not reduce available liquidity under AEP's credit facilities. | ||||||||||||||||||||
Comparative Accounts Receivable Information | Three Months Ended | Nine Months Ended | ||||||||||||||||||
September 30, | September 30, | |||||||||||||||||||
2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(dollars in millions) | ||||||||||||||||||||
Effective Interest Rates on Securitization of | ||||||||||||||||||||
Accounts Receivable | 0.23 | % | 0.26 | % | 0.23 | % | 0.26 | % | ||||||||||||
Net Uncollectible Accounts Receivable | ||||||||||||||||||||
Written Off | $ | 12 | $ | 8 | $ | 26 | $ | 21 | ||||||||||||
Customer Accounts Receivable Managed Portfolio | September 30, | December 31, | ||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Accounts Receivable Retained Interest and Pledged as Collateral | ||||||||||||||||||||
Less Uncollectible Accounts | $ | 965 | $ | 835 | ||||||||||||||||
Total Principal Outstanding | 700 | 657 | ||||||||||||||||||
Delinquent Securitized Accounts Receivable | 60 | 37 | ||||||||||||||||||
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | 17 | 21 | ||||||||||||||||||
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | 266 | 316 | ||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Long-term Debt Issuances | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Net | |||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate | Average Interest Rate | ||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | September 30, | December 31, | ||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Long-term Debt Issuances | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Net | |||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate | Average Interest Rate | ||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | September 30, | December 31, | ||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Long-term Debt Issuances | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
APCo | Pollution Control Bonds | $ | 30,000 | 3.25 | 2018 | |||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 3.25 | 2018 | ||||||||||||||||
I&M | Notes Payable | 101,354 | Variable | 2017 | ||||||||||||||||
I&M | Senior Unsecured Notes | 250,000 | 3.2 | 2023 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Other Long-term Debt | 600,000 | (c) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | Variable | 2014 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | Variable | 2014 | ||||||||||||||||
OPCo | Securitization Bonds | 164,900 | 0.96 | 2018 | ||||||||||||||||
OPCo | Securitization Bonds | 102,508 | 2.05 | 2020 | ||||||||||||||||
(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. | ||||||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
(c) Draw on a $1 billion term credit facility due in May 2015. | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Net | |||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
Nonutility Money Pool Activity | ||||||||||||||||||||
Maximum | Maximum | Average | Average | Borrowings | ||||||||||||||||
Borrowings | Loans | Borrowings | Loans | from the Nonutility | ||||||||||||||||
from the Nonutility | to the Nonutility | from the Nonutility | to the Nonutility | Money Pool as of | ||||||||||||||||
Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
$ | 1,047 | $ | 1,027 | $ | 201 | $ | 208 | $ | 338 | |||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate | Average Interest Rate | ||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool | Maximum | Minimum | Maximum | Minimum | Average | Average | ||||||||||||||
Interest Rate | Interest Rate | Interest Rate | Interest Rate | Interest Rate | Interest Rate | |||||||||||||||
for Funds | for Funds | for Funds | for Funds | for Funds | for Funds | |||||||||||||||
Nine Months | Borrowed from | Borrowed from | Loaned to | Loaned to | Borrowed from | Loaned to | ||||||||||||||
Ended | the Nonutility | the Nonutility | the Nonutility | the Nonutility | the Nonutility | the Nonutility | ||||||||||||||
September 30, | Money Pool | Money Pool | Money Pool | Money Pool | Money Pool | Money Pool | ||||||||||||||
2013 | 0.61 | % | 0.53 | % | 0.35 | % | 0.32 | % | 0.56 | % | 0.34 | % | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | September 30, | December 31, | ||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Net | |||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate | Average Interest Rate | ||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | September 30, | December 31, | ||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 | ||||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Retirements and Principal Payments | Principal | Interest | ||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 21 | 13.718 | 2026 | |||||||||||||||
APCo | Pollution Control Bonds | 30,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Pollution Control Bonds | 40,000 | 4.85 | 2013 | ||||||||||||||||
APCo | Senior Unsecured Notes | 275,000 | Variable | 2013 | ||||||||||||||||
I&M | Notes Payable | 6,083 | 5.44 | 2013 | ||||||||||||||||
I&M | Notes Payable | 9,811 | 4 | 2014 | ||||||||||||||||
I&M | Notes Payable | 12,071 | Variable | 2015 | ||||||||||||||||
I&M | Notes Payable | 14,945 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10,350 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 31,289 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 8,204 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 705 | 6 | 2025 | ||||||||||||||||
I&M | Other Long-term Debt | 4,086 | Variable | 2015 | ||||||||||||||||
I&M | Pollution Control Bonds | 40,000 | 5.25 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 200,000 | (b) | Variable | 2015 | |||||||||||||||
OPCo | Pollution Control Bonds | 56,000 | 5.1 | 2013 | ||||||||||||||||
OPCo | Pollution Control Bonds | 50,000 | 5.15 | 2026 | ||||||||||||||||
OPCo | Pollution Control Bonds | 65,000 | 4.9 | 2037 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.5 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 250,000 | 5.75 | 2013 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 6.38 | 2033 | ||||||||||||||||
PSO | Notes Payable | 301 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 3,250 | 4.58 | 2032 | ||||||||||||||||
(b) Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | ||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Net | |||||||||||||||||||
Loans to | ||||||||||||||||||||
Maximum | Maximum | Average | Average | (Borrowings from) | Authorized | |||||||||||||||
Borrowings | Loans | Borrowings | Loans | the Utility | Short-term | |||||||||||||||
from the Utility | to the Utility | from the Utility | to the Utility | Money Pool as of | Borrowing | |||||||||||||||
Company | Money Pool | Money Pool | Money Pool | Money Pool | 30-Sep-13 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 331,771 | $ | 39,372 | $ | 126,391 | $ | 23,632 | $ | -253,352 | $ | 600,000 | ||||||||
I&M | 23,135 | 384,435 | 8,308 | 239,647 | 322,476 | 500,000 | ||||||||||||||
OPCo | 410,456 | 415,605 | 228,719 | 59,047 | 9,401 | 600,000 | ||||||||||||||
PSO | 46,806 | 52,734 | 18,658 | 18,808 | 19,442 | 300,000 | ||||||||||||||
SWEPCo | 15,386 | 153,830 | 4,154 | 38,449 | 18,634 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Nine Months Ended September 30, | |||||||||||||||||||
2013 | 2012 | |||||||||||||||||||
Maximum Interest Rate | 0.43 | % | 0.56 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.44 | % | ||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | Average Interest Rate | Average Interest Rate | ||||||||||||||||||
for Funds Borrowed | for Funds Loaned | |||||||||||||||||||
from the Utility Money Pool for | to the Utility Money Pool for | |||||||||||||||||||
Nine Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
APCo | 0.33 | % | 0.48 | % | 0.34 | % | 0.48 | % | ||||||||||||
I&M | 0.36 | % | - | % | 0.33 | % | 0.47 | % | ||||||||||||
OPCo | 0.34 | % | 0.47 | % | 0.32 | % | 0.5 | % | ||||||||||||
PSO | 0.34 | % | - | % | 0.32 | % | 0.47 | % | ||||||||||||
SWEPCo | 0.33 | % | 0.53 | % | 0.36 | % | 0.47 | % | ||||||||||||
Short Term Debt | 30-Sep-13 | 31-Dec-12 | ||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Company | Type of Debt | Amount | Rate (a) | Amount | Rate (a) | |||||||||||||||
(in thousands) | (in thousands) | |||||||||||||||||||
SWEPCo | Line of Credit – Sabine | $ | - | - | % | $ | 2,603 | 1.82 | % | |||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | September 30, | December 31, | ||||||||||||||||||
Company | 2013 | 2012 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 135,579 | $ | 153,719 | ||||||||||||||||
I&M | 143,804 | 123,447 | ||||||||||||||||||
OPCo | 321,054 | 300,675 | ||||||||||||||||||
PSO | 147,586 | 85,530 | ||||||||||||||||||
SWEPCo | 180,922 | 132,449 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,575 | $ | 1,703 | $ | 4,590 | $ | 5,389 | ||||||||||||
I&M | 1,762 | 1,674 | 4,744 | 4,738 | ||||||||||||||||
OPCo | 5,076 | 5,362 | 14,440 | 15,900 | ||||||||||||||||
PSO | 1,549 | 1,990 | 4,314 | 5,547 | ||||||||||||||||
SWEPCo | 1,649 | 1,786 | 4,413 | 4,720 | ||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | ||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 340,438 | $ | 351,570 | $ | 1,081,615 | $ | 993,975 | ||||||||||||
I&M | 384,316 | 358,936 | 1,097,563 | 1,018,933 | ||||||||||||||||
OPCo | 658,829 | 790,115 | 2,017,746 | 2,284,749 | ||||||||||||||||
PSO | 382,167 | 342,819 | 944,062 | 919,343 | ||||||||||||||||
SWEPCo | 450,294 | 444,461 | 1,171,306 | 1,145,182 |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 9 Months Ended | ||||||||||||||||||||
Sep. 30, 2013 | |||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | ||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Ohio | |||||||||||||||||||||
TCC | Phase-in- | Protected | |||||||||||||||||||
SWEPCo | I&M | Transition | Recovery | Cell | |||||||||||||||||
Sabine | DCC Fuel | AEP Credit | Funding | Funding | of EIS | ||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | $ | 65 | $ | 155 | $ | 972 | $ | 197 | $ | 12 | $ | 146 | |||||||||
Net Property, Plant and Equipment | 160 | 181 | - | - | - | - | |||||||||||||||
Other Noncurrent Assets | 56 | 79 | 1 | 1,989 | (a) | 261 | (b) | 4 | |||||||||||||
Total Assets | $ | 281 | $ | 415 | $ | 973 | $ | 2,186 | $ | 273 | $ | 150 | |||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32 | $ | 139 | $ | 856 | $ | 298 | $ | 36 | $ | 46 | |||||||||
Noncurrent Liabilities | 249 | 276 | 1 | 1,870 | 236 | 70 | |||||||||||||||
Equity | - | - | 116 | 18 | 1 | 34 | |||||||||||||||
Total Liabilities and Equity | $ | 281 | $ | 415 | $ | 973 | $ | 2,186 | $ | 273 | $ | 150 | |||||||||
(a) Includes an intercompany item eliminated in consolidation of $84 million. | |||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $121 million. | |||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | |||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
31-Dec-12 | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
TCC | |||||||||||||||||||||
SWEPCo | I&M | Transition | Protected Cell | ||||||||||||||||||
Sabine | DCC Fuel | AEP Credit | Funding | of EIS | |||||||||||||||||
ASSETS | |||||||||||||||||||||
Current Assets | $ | 57 | $ | 133 | $ | 843 | $ | 250 | $ | 130 | |||||||||||
Net Property, Plant and Equipment | 170 | 176 | - | - | - | ||||||||||||||||
Other Noncurrent Assets | 55 | 92 | 1 | 2,167 | (a) | 4 | |||||||||||||||
Total Assets | $ | 282 | $ | 401 | $ | 844 | $ | 2,417 | $ | 134 | |||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32 | $ | 121 | $ | 800 | $ | 304 | $ | 43 | |||||||||||
Noncurrent Liabilities | 250 | 280 | 1 | 2,095 | 66 | ||||||||||||||||
Equity | - | - | 43 | 18 | 25 | ||||||||||||||||
Total Liabilities and Equity | $ | 282 | $ | 401 | $ | 844 | $ | 2,417 | $ | 134 | |||||||||||
(a) Includes an intercompany item eliminated in consolidation of $89 million. | |||||||||||||||||||||
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 66,114 | $ | 65,051 | $ | 177,840 | $ | 177,790 | |||||||||||||
OPCo | 37,255 | 46,184 | 107,876 | 149,424 | |||||||||||||||||
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 26,323 | $ | 26,323 | $ | 25,498 | $ | 25,498 | |||||||||||||
OPCo | 9,708 | 9,708 | 16,302 | 16,302 | |||||||||||||||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | |||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES | ||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
September 30, 2013 and December 31, 2012 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
DCC Fuel | |||||||||||||||||||||
ASSETS | 2013 | 2012 | |||||||||||||||||||
Current Assets | $ | 155,448 | $ | 132,886 | |||||||||||||||||
Net Property, Plant and Equipment | 180,541 | 176,065 | |||||||||||||||||||
Other Noncurrent Assets | 78,689 | 92,473 | |||||||||||||||||||
Total Assets | $ | 414,678 | $ | 401,424 | |||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 138,796 | $ | 120,873 | |||||||||||||||||
Noncurrent Liabilities | 275,882 | 280,551 | |||||||||||||||||||
Total Liabilities and Equity | $ | 414,678 | $ | 401,424 | |||||||||||||||||
Ohio Power Co [Member] | Billings from AEP Generating Co [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 66,114 | $ | 65,051 | $ | 177,840 | $ | 177,790 | |||||||||||||
OPCo | 37,255 | 46,184 | 107,876 | 149,424 | |||||||||||||||||
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
Ohio Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
I&M | $ | 26,323 | $ | 26,323 | $ | 25,498 | $ | 25,498 | |||||||||||||
OPCo | 9,708 | 9,708 | 16,302 | 16,302 | |||||||||||||||||
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | |||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | OHIO POWER COMPANY AND SUBSIDIARIES | ||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
30-Sep-13 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Ohio | |||||||||||||||||||||
Phase-in- | |||||||||||||||||||||
Recovery | |||||||||||||||||||||
Funding | |||||||||||||||||||||
ASSETS | 2013 | ||||||||||||||||||||
Current Assets | $ | 12,021 | |||||||||||||||||||
Other Noncurrent Assets (a) | 261,005 | ||||||||||||||||||||
Total Assets | $ | 273,026 | |||||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 35,550 | |||||||||||||||||||
Noncurrent Liabilities | 236,139 | ||||||||||||||||||||
Equity | 1,337 | ||||||||||||||||||||
Total Liabilities and Equity | $ | 273,026 | |||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation of $121 million. | |||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | |||||||||||||||||||||
Billings from Significant Variable Interest | |||||||||||||||||||||
Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||
Company | 2013 | 2012 | 2013 | 2012 | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 39,779 | $ | 47,820 | $ | 120,315 | $ | 130,260 | |||||||||||||
I&M | 25,988 | 31,134 | 82,192 | 88,618 | |||||||||||||||||
OPCo | 58,528 | 72,751 | 169,949 | 193,686 | |||||||||||||||||
PSO | 19,535 | 21,728 | 57,504 | 60,625 | |||||||||||||||||
SWEPCo | 28,431 | 33,154 | 85,506 | 93,120 | |||||||||||||||||
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | |||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | |||||||||||||||||||||
30-Sep-13 | 31-Dec-12 | ||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | ||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 7,637 | $ | 7,637 | $ | 29,819 | $ | 29,819 | |||||||||||||
I&M | 6,560 | 6,560 | 17,911 | 17,911 | |||||||||||||||||
OPCo | 14,217 | 14,217 | 39,323 | 39,323 | |||||||||||||||||
PSO | 4,710 | 4,710 | 13,381 | 13,381 | |||||||||||||||||
SWEPCo | 6,778 | 6,778 | 19,669 | 19,669 | |||||||||||||||||
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | |||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED | ||||||||||||||||||||
VARIABLE INTEREST ENTITIES | |||||||||||||||||||||
September 30, 2013 and December 31, 2012 | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Sabine | |||||||||||||||||||||
ASSETS | 2013 | 2012 | |||||||||||||||||||
Current Assets | $ | 64,737 | $ | 56,535 | |||||||||||||||||
Net Property, Plant and Equipment | 160,575 | 170,436 | |||||||||||||||||||
Other Noncurrent Assets | 55,760 | 55,076 | |||||||||||||||||||
Total Assets | $ | 281,072 | $ | 282,047 | |||||||||||||||||
LIABILITIES AND EQUITY | |||||||||||||||||||||
Current Liabilities | $ | 32,005 | $ | 31,446 | |||||||||||||||||
Noncurrent Liabilities | 248,745 | 250,340 | |||||||||||||||||||
Equity | 322 | 261 | |||||||||||||||||||
Total Liabilities and Equity | $ | 281,072 | $ | 282,047 | |||||||||||||||||
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | |||||||||||||||||||||
Companys Investment In Joint Venture | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Capital Contribution from SWEPCo | $ | 7,643 | $ | 7,643 | $ | 7,643 | $ | 7,643 | |||||||||||||
Retained Earnings | 1,102 | 1,102 | 946 | 946 | |||||||||||||||||
SWEPCo's Guarantee of Debt | - | 44,897 | - | 49,564 | |||||||||||||||||
Total Investment in DHLC | $ | 8,745 | $ | 53,642 | $ | 8,589 | $ | 58,153 | |||||||||||||
Dolet Hills Lignite Co, LLC [Member] | |||||||||||||||||||||
Companys Investment In Joint Venture | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Capital Contribution from SWEPCo | $ | 8 | $ | 8 | $ | 8 | $ | 8 | |||||||||||||
Retained Earnings | 1 | 1 | 1 | 1 | |||||||||||||||||
SWEPCo's Guarantee of Debt | - | 45 | - | 49 | |||||||||||||||||
Total Investment in DHLC | $ | 9 | $ | 54 | $ | 9 | $ | 58 | |||||||||||||
PATH West Virginia Transmission Co, LLC [Member] | |||||||||||||||||||||
Companys Investment In Joint Venture | 30-Sep-13 | 31-Dec-12 | |||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | ||||||||||||||||||
the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Capital Contribution from AEP | $ | 19 | $ | 19 | $ | 19 | $ | 19 | |||||||||||||
Retained Earnings | 14 | 14 | 12 | 12 | |||||||||||||||||
Total Investment in PATH-WV | $ | 33 | $ | 33 | $ | 31 | $ | 31 |
Sustainable_Cost_Reductions_Ta
Sustainable Cost Reductions (Tables) | 9 Months Ended | |||||||||||||||||||
Sep. 30, 2013 | ||||||||||||||||||||
Remaining Accrual | Sustainable Cost | |||||||||||||||||||
Reduction Activity | ||||||||||||||||||||
(in millions) | ||||||||||||||||||||
Balance as of December 31, 2012 | $ | 25 | ||||||||||||||||||
Incurred | 16 | |||||||||||||||||||
Settled | -30 | |||||||||||||||||||
Adjustments | -9 | |||||||||||||||||||
Balance as of September 30, 2013 | $ | 2 | ||||||||||||||||||
Appalachian Power Co [Member] | ||||||||||||||||||||
Total Cost Incurred | Company | Total Cost Incurred | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
Remaining Accrual | Expense | Incurred for | Remaining | |||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
Indiana Michigan Power Co [Member] | ||||||||||||||||||||
Total Cost Incurred | Company | Total Cost Incurred | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
Remaining Accrual | Expense | Incurred for | Remaining | |||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
Ohio Power Co [Member] | ||||||||||||||||||||
Total Cost Incurred | Company | Total Cost Incurred | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
Remaining Accrual | Expense | Incurred for | Remaining | |||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||||||||||||
Total Cost Incurred | Company | Total Cost Incurred | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
Remaining Accrual | Expense | Incurred for | Remaining | |||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 | ||||||||||||||
Southwestern Electric Power Co [Member] | ||||||||||||||||||||
Total Cost Incurred | Company | Total Cost Incurred | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 8,472 | ||||||||||||||||||
I&M | 5,678 | |||||||||||||||||||
OPCo | 13,498 | |||||||||||||||||||
PSO | 3,675 | |||||||||||||||||||
SWEPCo | 5,709 | |||||||||||||||||||
Remaining Accrual | Expense | Incurred for | Remaining | |||||||||||||||||
Balance as of | Allocation from | Registrant | Balance as of | |||||||||||||||||
Company | 31-Dec-12 | AEPSC | Subsidiaries | Settled | Adjustments | 30-Sep-13 | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 1,321 | $ | 1,017 | $ | - | $ | -1,575 | $ | -730 | $ | 33 | ||||||||
I&M | 1,357 | 736 | - | -1,681 | -373 | 39 | ||||||||||||||
OPCo | 3,450 | 1,354 | 6,114 | -8,837 | -1,630 | 451 | ||||||||||||||
PSO | 652 | 325 | - | -483 | -471 | 23 | ||||||||||||||
SWEPCo | 627 | 622 | - | -1,620 | 405 | 34 |
Significant_Accounting_Matters3
Significant Accounting Matters (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Basic and Diluted EPS Calculations | ||||
Earnings Attributable to AEP Common Shareholders | $433,000,000 | $487,000,000 | $1,134,000,000 | $1,238,000,000 |
Weighted Average Number of Basic AEP Common Shares Outstanding | 486,932,747 | 484,979,543 | 486,353,876 | 484,437,875 |
Total Basic Earnings Per Share Attributable to AEP Common Shareholders | $0.89 | $1 | $2.33 | $2.55 |
Weighted Average Dilutive Effect of: | ||||
Weighted Average Number of Diluted AEP Common Shares Outstanding | 487,258,905 | 485,362,858 | 486,792,914 | 484,826,123 |
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders | $0.89 | $1 | $2.33 | $2.55 |
Amounts Attributable to AEP Common Shareholders | ||||
Net Income | 433,000,000 | 487,000,000 | 1,134,000,000 | 1,238,000,000 |
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Antidilutive Shares Outstanding | 0 | 0 | ||
Ohio Power Co [Member] | ||||
Financial Impact of Asset Transfer [Abstract] | ||||
Decrease in Total Assets Due to the Transfer of Cook Coal Terminal from OPCo to AEGCo | 43,300,000 | 43,300,000 | ||
Decrease in Total Liabilities Due to the Transfer of Cook Coal Terminal from OPCo to AEGCo | 40,600,000 | 40,600,000 | ||
Southwestern Electric Power Co [Member] | ||||
Basic and Diluted EPS Calculations | ||||
Earnings Attributable to AEP Common Shareholders | 6,862,000 | 88,263,000 | 46,491,000 | 177,416,000 |
Amounts Attributable to AEP Common Shareholders | ||||
Net Income | $6,862,000 | $88,263,000 | $46,491,000 | $177,416,000 |
Employee Stock Option [Member] | ||||
Weighted Average Dilutive Effect of: | ||||
Weighted Average Dilutive Effect of Shares | 0 | 100,000 | 0 | 100,000 |
Dilutive Securities, Effect on Basic Earnings Per Share | $0 | $0 | $0 | $0 |
Restricted Stock Units [Member] | ||||
Weighted Average Dilutive Effect of: | ||||
Weighted Average Dilutive Effect of Shares | 400,000 | 300,000 | 400,000 | 300,000 |
Dilutive Securities, Effect on Basic Earnings Per Share | $0 | $0 | $0 | $0 |
Comprehensive_Income_Details
Comprehensive Income (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |||||||||||||||||||||||||||||||||
Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | |||||||||||||||||||||||||||||||||||||
Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Securities Available for Sale [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Pension and OPEB [Member] | Pension and OPEB [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Commodity [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | Interest Rate and Foreign Currency [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | Cash Flow Hedges [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Beginning Balance in AOCI | ($313,000,000) | ($337,000,000) | $5,000,000 | $4,000,000 | ($294,000,000) | ($303,000,000) | $1,000,000 | ($8,000,000) | ($25,000,000) | ($30,000,000) | ($27,835,000) | ($29,898,000) | ($30,615,000) | ($31,331,000) | $197,000 | ($644,000) | $2,583,000 | $2,077,000 | ($25,088,000) | ($28,883,000) | ($8,439,000) | ($8,790,000) | $147,000 | ($446,000) | ($16,796,000) | ($19,647,000) | ($158,665,000) | ($165,725,000) | ($166,369,000) | ($172,908,000) | $289,000 | ($912,000) | $7,415,000 | $8,095,000 | $6,060,000 | $6,481,000 | ($21,000) | $21,000 | $6,081,000 | $6,460,000 | ($16,901,000) | ($17,860,000) | ($2,438,000) | ($2,311,000) | ($26,000) | $22,000 | ($14,437,000) | ($15,571,000) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Distribution of Cook Coal Terminal to Parent | 19,652,000 | -2,651,000 | 19,652,000 | 19,652,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Change in Fair Value Recognized in AOCI | 2,000,000 | 15,000,000 | 1,000,000 | 2,000,000 | 0 | 0 | 1,000,000 | 11,000,000 | 0 | 2,000,000 | -47,000 | 684,000 | 0 | 0 | -47,000 | 684,000 | 0 | 0 | -49,000 | 2,691,000 | 0 | 0 | -49,000 | 443,000 | 0 | 2,248,000 | -86,000 | 907,000 | 0 | 0 | -86,000 | 907,000 | 0 | 0 | 32,000 | 8,000 | 32,000 | 7,000 | 0 | 1,000 | 40,000 | 13,000 | 0 | 0 | 40,000 | 13,000 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amounts Reclassified from AOCI | 5,000,000 | 16,000,000 | 0 | 0 | 7,000,000 | 16,000,000 | -3,000,000 | -4,000,000 | 1,000,000 | 4,000,000 | 5,000,000 | 16,000,000 | -2,000,000 | 0 | 0 | 0 | 7,000,000 | 16,000,000 | 428,000 | 1,760,000 | 359,000 | 1,075,000 | -184,000 | -74,000 | 253,000 | 759,000 | 428,000 | 1,760,000 | 69,000 | 685,000 | 359,000 | 1,075,000 | 467,000 | 1,522,000 | 174,000 | 525,000 | -117,000 | -16,000 | 410,000 | 1,013,000 | 467,000 | 1,522,000 | 293,000 | 997,000 | 174,000 | 525,000 | 2,396,000 | 8,463,000 | 2,985,000 | 9,524,000 | -250,000 | -42,000 | -339,000 | -1,019,000 | 2,396,000 | 8,463,000 | -589,000 | -1,061,000 | 2,985,000 | 9,524,000 | -204,000 | -601,000 | -14,000 | -31,000 | -190,000 | -570,000 | -204,000 | -601,000 | 485,000 | 1,471,000 | -64,000 | -191,000 | -17,000 | -38,000 | 566,000 | 1,700,000 | 485,000 | 1,471,000 | 549,000 | 1,662,000 | -64,000 | -191,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Current Period Other Comprehensive Income | 7,000,000 | 21,000,000 | 31,000,000 | 16,000,000 | 1,000,000 | 2,000,000 | 7,000,000 | 16,000,000 | -2,000,000 | 7,000,000 | 1,000,000 | 6,000,000 | 381,000 | 2,618,000 | 2,444,000 | 4,444,000 | 359,000 | 1,075,000 | -231,000 | 610,000 | 253,000 | 759,000 | 418,000 | -126,000 | 4,213,000 | -4,546,000 | 174,000 | 525,000 | -166,000 | 427,000 | 410,000 | 3,261,000 | 2,310,000 | 5,016,000 | 9,370,000 | 9,926,000 | 2,985,000 | 9,524,000 | -336,000 | 865,000 | -339,000 | -1,019,000 | -172,000 | -593,000 | -465,000 | 18,000 | -24,000 | -190,000 | -569,000 | 525,000 | 864,000 | 1,484,000 | -183,000 | -64,000 | -191,000 | 23,000 | -25,000 | 566,000 | 1,700,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Ending Balance in AOCI | -306,000,000 | -306,000,000 | 6,000,000 | 6,000,000 | -287,000,000 | -287,000,000 | -1,000,000 | -1,000,000 | -24,000,000 | -24,000,000 | -27,454,000 | -27,454,000 | -30,256,000 | -30,256,000 | -34,000 | -34,000 | 2,836,000 | 2,836,000 | -24,670,000 | -24,670,000 | -8,265,000 | -8,265,000 | -19,000 | -19,000 | -16,386,000 | -16,386,000 | -136,703,000 | -136,703,000 | -143,732,000 | -143,732,000 | -47,000 | -47,000 | 7,076,000 | 7,076,000 | 5,888,000 | 5,888,000 | -3,000 | -3,000 | 5,891,000 | 5,891,000 | -16,376,000 | -16,376,000 | -2,502,000 | -2,502,000 | -3,000 | -3,000 | -13,871,000 | -13,871,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility Operations Revenues | 3,797,000,000 | 3,814,000,000 | 10,539,000,000 | 10,412,000,000 | 0 | 0 | -1,000,000 | 0 | -1,000,000 | 0 | 0 | 0 | 756,606,000 | 776,066,000 | 2,299,587,000 | 2,161,901,000 | -4,000 | -7,000 | -75,000 | -4,000 | -53,000 | -7,000 | 537,453,000 | 499,078,000 | 1,518,357,000 | 1,371,070,000 | -10,000 | -19,000 | -173,000 | -10,000 | -89,000 | -19,000 | 959,816,000 | 1,114,339,000 | 2,710,990,000 | 3,084,657,000 | -23,000 | -47,000 | -461,000 | -23,000 | -246,000 | -47,000 | 408,803,000 | 364,851,000 | 986,008,000 | 968,683,000 | 0 | 0 | 0 | 0 | 534,196,000 | 473,391,000 | 1,324,325,000 | 1,196,753,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Revenues | 379,000,000 | 342,000,000 | 1,045,000,000 | 920,000,000 | -1,000,000 | -4,000,000 | -3,000,000 | -1,000,000 | -8,000,000 | -4,000,000 | 0 | 0 | 2,569,000 | 3,192,000 | 6,833,000 | 7,950,000 | 514,000 | 768,000 | 3,552,000 | 4,453,000 | 2,827,000 | 5,391,000 | 12,982,000 | 14,638,000 | 621,000 | 1,156,000 | 2,865,000 | 2,654,000 | 441,000 | 680,000 | 1,163,000 | 1,403,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Electricity for Resale | 373,000,000 | 327,000,000 | 1,103,000,000 | 855,000,000 | 0 | 13,000,000 | -1,000,000 | 0 | 3,000,000 | 13,000,000 | 0 | 0 | 47,391,000 | 45,196,000 | 172,334,000 | 155,421,000 | 35,000 | 411,000 | 21,000 | 35,000 | 47,000 | 411,000 | 32,976,000 | 23,399,000 | 111,602,000 | 88,797,000 | 88,000 | 1,074,000 | 47,000 | 88,000 | 115,000 | 1,074,000 | 34,568,000 | 46,146,000 | 114,911,000 | 156,384,000 | 221,000 | 2,806,000 | 129,000 | 221,000 | 309,000 | 2,806,000 | 55,915,000 | 75,719,000 | 179,405,000 | 145,983,000 | 0 | 0 | 0 | 0 | 37,505,000 | 35,109,000 | 120,273,000 | 97,150,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Operation Expense | 677,000,000 | 775,000,000 | 2,079,000,000 | 2,150,000,000 | 64,508,000 | 92,700,000 | 223,180,000 | 239,704,000 | -4,000 | -20,000 | -14,000 | -4,000 | -38,000 | -20,000 | 136,702,000 | 141,728,000 | 414,418,000 | 411,218,000 | -1,000 | -11,000 | -8,000 | -1,000 | -23,000 | -11,000 | 159,965,000 | 189,566,000 | 481,417,000 | 481,994,000 | -6,000 | -30,000 | -20,000 | -6,000 | -57,000 | -30,000 | 60,566,000 | 58,975,000 | 162,032,000 | 154,834,000 | 0 | -11,000 | -10,000 | 0 | -25,000 | -11,000 | 62,108,000 | 60,217,000 | 182,351,000 | 165,877,000 | 1,000 | -8,000 | -12,000 | 1,000 | -28,000 | -8,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maintenance Expense | 261,000,000 | 255,000,000 | 839,000,000 | 769,000,000 | 49,924,000 | 47,047,000 | 207,870,000 | 131,212,000 | 12,000 | 3,000 | -11,000 | 12,000 | -29,000 | 3,000 | 43,448,000 | 44,308,000 | 139,200,000 | 133,817,000 | 4,000 | 0 | -5,000 | 4,000 | -14,000 | 0 | 71,670,000 | 73,024,000 | 218,962,000 | 227,643,000 | 7,000 | -3,000 | -11,000 | 7,000 | -26,000 | -3,000 | 25,071,000 | 25,685,000 | 78,396,000 | 78,863,000 | 5,000 | 3,000 | -5,000 | 5,000 | -9,000 | 3,000 | 24,654,000 | 27,816,000 | 84,725,000 | 78,835,000 | 4,000 | 1,000 | -7,000 | 4,000 | -14,000 | 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | 0 | 0 | 3,000 | -9,000 | -15,000 | 3,000 | -34,000 | -9,000 | 1,000 | -6,000 | -10,000 | 1,000 | -20,000 | -6,000 | 1,000 | -15,000 | -21,000 | 1,000 | -44,000 | -15,000 | 5,000 | 1,000 | -7,000 | 5,000 | -14,000 | 1,000 | 3,000 | -3,000 | -8,000 | 3,000 | -16,000 | -3,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets/(Liabilities), Net | 0 | [1] | 2,000,000 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 2,000,000 | [1] | 0 | [1] | 0 | [1] | 114,000 | [1] | 1,515,000 | [1] | -190,000 | [1] | 114,000 | [1] | -9,000 | [1] | 1,515,000 | [1] | 20,000 | [1] | 265,000 | [1] | -31,000 | [1] | 20,000 | [1] | 7,000 | [1] | 265,000 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subtotal - Commodity | -3,000,000 | 0 | 0 | 0 | 11,000,000 | 25,000,000 | -5,000,000 | -6,000,000 | 2,000,000 | 6,000,000 | 106,000 | 1,053,000 | 552,000 | 1,654,000 | -284,000 | -116,000 | 390,000 | 1,169,000 | 451,000 | 1,534,000 | 268,000 | 808,000 | -180,000 | -24,000 | 631,000 | 1,558,000 | -906,000 | -1,632,000 | 4,593,000 | 14,652,000 | -384,000 | -64,000 | -522,000 | -1,568,000 | -314,000 | -924,000 | -22,000 | -48,000 | -292,000 | -876,000 | 845,000 | 2,558,000 | -98,000 | -294,000 | -27,000 | -58,000 | 872,000 | 2,616,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate and Foreign Currency: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation and Amortization Expense | 447,000,000 | 470,000,000 | 1,310,000,000 | 1,353,000,000 | 84,513,000 | 86,636,000 | 255,656,000 | 252,188,000 | 0 | 0 | 0 | 0 | 45,393,000 | 37,734,000 | 131,991,000 | 109,273,000 | 0 | 0 | 0 | 0 | 94,802,000 | 130,026,000 | 289,472,000 | 401,465,000 | 1,000 | 3,000 | 2,000 | 1,000 | 5,000 | 3,000 | 24,191,000 | 24,433,000 | 72,449,000 | 71,356,000 | 0 | 0 | 0 | 0 | 41,846,000 | 35,144,000 | 132,460,000 | 103,820,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | 225,000,000 | 233,000,000 | 685,000,000 | 697,000,000 | 1,000,000 | 3,000,000 | 0 | 0 | 0 | 0 | 2,000,000 | 1,000,000 | 6,000,000 | 3,000,000 | 47,375,000 | 50,071,000 | 143,707,000 | 153,323,000 | 261,000 | 799,000 | 390,000 | 261,000 | 1,169,000 | 799,000 | 23,932,000 | 26,307,000 | 72,579,000 | 76,733,000 | 149,000 | 447,000 | 631,000 | 149,000 | 1,558,000 | 447,000 | 45,070,000 | 53,576,000 | 142,487,000 | 160,984,000 | -341,000 | -1,023,000 | -524,000 | -341,000 | -1,573,000 | -1,023,000 | 13,417,000 | 13,735,000 | 40,016,000 | 42,212,000 | -190,000 | -569,000 | -292,000 | -190,000 | -876,000 | -569,000 | 32,614,000 | 21,498,000 | 100,151,000 | 65,210,000 | 567,000 | 2,000,000 | 872,000 | 567,000 | 2,616,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -3,000,000 | 0 | 0 | 0 | 11,000,000 | 25,000,000 | -5,000,000 | -6,000,000 | 2,000,000 | 6,000,000 | 106,000 | 1,053,000 | 552,000 | 1,654,000 | -284,000 | -116,000 | 390,000 | 1,169,000 | 451,000 | 1,534,000 | 268,000 | 808,000 | -180,000 | -24,000 | 631,000 | 1,558,000 | -906,000 | -1,632,000 | 4,593,000 | 14,652,000 | -384,000 | -64,000 | -522,000 | -1,568,000 | -314,000 | -924,000 | -22,000 | -48,000 | -292,000 | -876,000 | 845,000 | 2,558,000 | -98,000 | -294,000 | -27,000 | -58,000 | 872,000 | 2,616,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -3,000,000 | 0 | 0 | 0 | 11,000,000 | 25,000,000 | -5,000,000 | -6,000,000 | 2,000,000 | 6,000,000 | 106,000 | 1,053,000 | 552,000 | 1,654,000 | -284,000 | -116,000 | 390,000 | 1,169,000 | 451,000 | 1,534,000 | 268,000 | 808,000 | -180,000 | -24,000 | 631,000 | 1,558,000 | -906,000 | -1,632,000 | 4,593,000 | 14,652,000 | -384,000 | -64,000 | -522,000 | -1,568,000 | -314,000 | -924,000 | -22,000 | -48,000 | -292,000 | -876,000 | 845,000 | 2,558,000 | -98,000 | -294,000 | -27,000 | -58,000 | 872,000 | 2,616,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax (Expense) Credit | -257,000,000 | -241,000,000 | -520,000,000 | -620,000,000 | -1,000,000 | 0 | 0 | 0 | 4,000,000 | 9,000,000 | -41,645,000 | -34,185,000 | -108,554,000 | -120,377,000 | 37,000 | 368,000 | 193,000 | 579,000 | -27,953,000 | -16,974,000 | -69,102,000 | -45,755,000 | 158,000 | 537,000 | 94,000 | 283,000 | -93,141,000 | -82,578,000 | -174,313,000 | -213,290,000 | -317,000 | -571,000 | 1,608,000 | 5,128,000 | -32,217,000 | -35,355,000 | -58,778,000 | -64,872,000 | -110,000 | -323,000 | -14,935,000 | -25,229,000 | -37,057,000 | -49,206,000 | 296,000 | 896,000 | -34,000 | -103,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5,000,000 | 16,000,000 | 0 | 0 | 7,000,000 | 16,000,000 | -3,000,000 | -4,000,000 | 1,000,000 | 4,000,000 | 5,000,000 | 16,000,000 | -2,000,000 | 0 | 0 | 0 | 7,000,000 | 16,000,000 | 428,000 | 1,760,000 | 359,000 | 1,075,000 | -184,000 | -74,000 | 253,000 | 759,000 | 428,000 | 1,760,000 | 69,000 | 685,000 | 359,000 | 1,075,000 | 467,000 | 1,522,000 | 174,000 | 525,000 | -117,000 | -16,000 | 410,000 | 1,013,000 | 467,000 | 1,522,000 | 293,000 | 997,000 | 174,000 | 525,000 | 2,396,000 | 8,463,000 | 2,985,000 | 9,524,000 | -250,000 | -42,000 | -339,000 | -1,019,000 | 2,396,000 | 8,463,000 | -589,000 | -1,061,000 | 2,985,000 | 9,524,000 | -204,000 | -601,000 | -14,000 | -31,000 | -190,000 | -570,000 | -204,000 | -601,000 | 485,000 | 1,471,000 | -64,000 | -191,000 | -17,000 | -38,000 | 566,000 | 1,700,000 | 485,000 | 1,471,000 | 549,000 | 1,662,000 | -64,000 | -191,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Gains and Losses on Available-for-Sale Securities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Income | 3,000,000 | 2,000,000 | 55,000,000 | 6,000,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | 225,000,000 | 233,000,000 | 685,000,000 | 697,000,000 | 1,000,000 | 3,000,000 | 0 | 0 | 0 | 0 | 2,000,000 | 1,000,000 | 6,000,000 | 3,000,000 | 47,375,000 | 50,071,000 | 143,707,000 | 153,323,000 | 261,000 | 799,000 | 390,000 | 261,000 | 1,169,000 | 799,000 | 23,932,000 | 26,307,000 | 72,579,000 | 76,733,000 | 149,000 | 447,000 | 631,000 | 149,000 | 1,558,000 | 447,000 | 45,070,000 | 53,576,000 | 142,487,000 | 160,984,000 | -341,000 | -1,023,000 | -524,000 | -341,000 | -1,573,000 | -1,023,000 | 13,417,000 | 13,735,000 | 40,016,000 | 42,212,000 | -190,000 | -569,000 | -292,000 | -190,000 | -876,000 | -569,000 | 32,614,000 | 21,498,000 | 100,151,000 | 65,210,000 | 567,000 | 2,000,000 | 872,000 | 567,000 | 2,616,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -3,000,000 | 0 | 0 | 0 | 11,000,000 | 25,000,000 | -5,000,000 | -6,000,000 | 2,000,000 | 6,000,000 | 106,000 | 1,053,000 | 552,000 | 1,654,000 | -284,000 | -116,000 | 390,000 | 1,169,000 | 451,000 | 1,534,000 | 268,000 | 808,000 | -180,000 | -24,000 | 631,000 | 1,558,000 | -906,000 | -1,632,000 | 4,593,000 | 14,652,000 | -384,000 | -64,000 | -522,000 | -1,568,000 | -314,000 | -924,000 | -22,000 | -48,000 | -292,000 | -876,000 | 845,000 | 2,558,000 | -98,000 | -294,000 | -27,000 | -58,000 | 872,000 | 2,616,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax (Expense) Credit | -257,000,000 | -241,000,000 | -520,000,000 | -620,000,000 | -1,000,000 | 0 | 0 | 0 | 4,000,000 | 9,000,000 | -41,645,000 | -34,185,000 | -108,554,000 | -120,377,000 | 37,000 | 368,000 | 193,000 | 579,000 | -27,953,000 | -16,974,000 | -69,102,000 | -45,755,000 | 158,000 | 537,000 | 94,000 | 283,000 | -93,141,000 | -82,578,000 | -174,313,000 | -213,290,000 | -317,000 | -571,000 | 1,608,000 | 5,128,000 | -32,217,000 | -35,355,000 | -58,778,000 | -64,872,000 | -110,000 | -323,000 | -14,935,000 | -25,229,000 | -37,057,000 | -49,206,000 | 296,000 | 896,000 | -34,000 | -103,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5,000,000 | 16,000,000 | 0 | 0 | 7,000,000 | 16,000,000 | -3,000,000 | -4,000,000 | 1,000,000 | 4,000,000 | 5,000,000 | 16,000,000 | -2,000,000 | 0 | 0 | 0 | 7,000,000 | 16,000,000 | 428,000 | 1,760,000 | 359,000 | 1,075,000 | -184,000 | -74,000 | 253,000 | 759,000 | 428,000 | 1,760,000 | 69,000 | 685,000 | 359,000 | 1,075,000 | 467,000 | 1,522,000 | 174,000 | 525,000 | -117,000 | -16,000 | 410,000 | 1,013,000 | 467,000 | 1,522,000 | 293,000 | 997,000 | 174,000 | 525,000 | 2,396,000 | 8,463,000 | 2,985,000 | 9,524,000 | -250,000 | -42,000 | -339,000 | -1,019,000 | 2,396,000 | 8,463,000 | -589,000 | -1,061,000 | 2,985,000 | 9,524,000 | -204,000 | -601,000 | -14,000 | -31,000 | -190,000 | -570,000 | -204,000 | -601,000 | 485,000 | 1,471,000 | -64,000 | -191,000 | -17,000 | -38,000 | 566,000 | 1,700,000 | 485,000 | 1,471,000 | 549,000 | 1,662,000 | -64,000 | -191,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amortization of Pension and OPEB | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Prior Service Cost (Credit) | -7,000,000 | -16,000,000 | -1,282,000 | -3,847,000 | -199,000 | -596,000 | -1,451,000 | -4,388,000 | -446,000 | -1,338,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Actuarial (Gains)/Losses | 18,000,000 | 41,000,000 | 1,834,000 | 5,501,000 | 467,000 | 1,404,000 | 6,044,000 | 19,040,000 | 348,000 | 1,044,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -3,000,000 | 0 | 0 | 0 | 11,000,000 | 25,000,000 | -5,000,000 | -6,000,000 | 2,000,000 | 6,000,000 | 106,000 | 1,053,000 | 552,000 | 1,654,000 | -284,000 | -116,000 | 390,000 | 1,169,000 | 451,000 | 1,534,000 | 268,000 | 808,000 | -180,000 | -24,000 | 631,000 | 1,558,000 | -906,000 | -1,632,000 | 4,593,000 | 14,652,000 | -384,000 | -64,000 | -522,000 | -1,568,000 | -314,000 | -924,000 | -22,000 | -48,000 | -292,000 | -876,000 | 845,000 | 2,558,000 | -98,000 | -294,000 | -27,000 | -58,000 | 872,000 | 2,616,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax (Expense) Credit | -257,000,000 | -241,000,000 | -520,000,000 | -620,000,000 | -1,000,000 | 0 | 0 | 0 | 4,000,000 | 9,000,000 | -41,645,000 | -34,185,000 | -108,554,000 | -120,377,000 | 37,000 | 368,000 | 193,000 | 579,000 | -27,953,000 | -16,974,000 | -69,102,000 | -45,755,000 | 158,000 | 537,000 | 94,000 | 283,000 | -93,141,000 | -82,578,000 | -174,313,000 | -213,290,000 | -317,000 | -571,000 | 1,608,000 | 5,128,000 | -32,217,000 | -35,355,000 | -58,778,000 | -64,872,000 | -110,000 | -323,000 | -14,935,000 | -25,229,000 | -37,057,000 | -49,206,000 | 296,000 | 896,000 | -34,000 | -103,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5,000,000 | 16,000,000 | 0 | 0 | 7,000,000 | 16,000,000 | -3,000,000 | -4,000,000 | 1,000,000 | 4,000,000 | 5,000,000 | 16,000,000 | -2,000,000 | 0 | 0 | 0 | 7,000,000 | 16,000,000 | 428,000 | 1,760,000 | 359,000 | 1,075,000 | -184,000 | -74,000 | 253,000 | 759,000 | 428,000 | 1,760,000 | 69,000 | 685,000 | 359,000 | 1,075,000 | 467,000 | 1,522,000 | 174,000 | 525,000 | -117,000 | -16,000 | 410,000 | 1,013,000 | 467,000 | 1,522,000 | 293,000 | 997,000 | 174,000 | 525,000 | 2,396,000 | 8,463,000 | 2,985,000 | 9,524,000 | -250,000 | -42,000 | -339,000 | -1,019,000 | 2,396,000 | 8,463,000 | -589,000 | -1,061,000 | 2,985,000 | 9,524,000 | -204,000 | -601,000 | -14,000 | -31,000 | -190,000 | -570,000 | -204,000 | -601,000 | 485,000 | 1,471,000 | -64,000 | -191,000 | -17,000 | -38,000 | 566,000 | 1,700,000 | 485,000 | 1,471,000 | 549,000 | 1,662,000 | -64,000 | -191,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5,000,000 | 16,000,000 | 0 | 0 | 7,000,000 | 16,000,000 | -3,000,000 | -4,000,000 | 1,000,000 | 4,000,000 | 5,000,000 | 16,000,000 | -2,000,000 | 0 | 0 | 0 | 7,000,000 | 16,000,000 | 428,000 | 1,760,000 | 359,000 | 1,075,000 | -184,000 | -74,000 | 253,000 | 759,000 | 428,000 | 1,760,000 | 69,000 | 685,000 | 359,000 | 1,075,000 | 467,000 | 1,522,000 | 174,000 | 525,000 | -117,000 | -16,000 | 410,000 | 1,013,000 | 467,000 | 1,522,000 | 293,000 | 997,000 | 174,000 | 525,000 | 2,396,000 | 8,463,000 | 2,985,000 | 9,524,000 | -250,000 | -42,000 | -339,000 | -1,019,000 | 2,396,000 | 8,463,000 | -589,000 | -1,061,000 | 2,985,000 | 9,524,000 | -204,000 | -601,000 | -14,000 | -31,000 | -190,000 | -570,000 | -204,000 | -601,000 | 485,000 | 1,471,000 | -64,000 | -191,000 | -17,000 | -38,000 | 566,000 | 1,700,000 | 485,000 | 1,471,000 | 549,000 | 1,662,000 | -64,000 | -191,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Beginning Balance in AOCI | -38,000,000 | -44,000,000 | -23,000,000 | -1,000,000 | -8,000,000 | -14,000,000 | -3,000,000 | -24,000,000 | -30,000,000 | -30,000,000 | -20,000,000 | -258,000 | -285,000 | -34,000 | -644,000 | -1,820,000 | -1,309,000 | 2,836,000 | 2,077,000 | 1,562,000 | 1,024,000 | -20,261,000 | -15,284,000 | -19,000 | -446,000 | -1,246,000 | -819,000 | -16,386,000 | -19,647,000 | -19,015,000 | -14,465,000 | 6,135,000 | 7,706,000 | -47,000 | -912,000 | -2,639,000 | -1,748,000 | 7,076,000 | 8,095,000 | 8,774,000 | 9,454,000 | 6,737,000 | 7,149,000 | -3,000 | 21,000 | -102,000 | -69,000 | 5,891,000 | 6,460,000 | 6,839,000 | 7,218,000 | -16,903,000 | -15,524,000 | -3,000 | 22,000 | -97,000 | -62,000 | -13,871,000 | -15,571,000 | -16,806,000 | -15,462,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 13,000,000 | -22,000,000 | 16,000,000 | -7,000,000 | -3,000,000 | -15,000,000 | 1,302,000 | -946,000 | 1,302,000 | -946,000 | 0 | 0 | -655,000 | -7,131,000 | 887,000 | -741,000 | -1,542,000 | -6,390,000 | 1,916,000 | -1,486,000 | 1,915,000 | -1,487,000 | 1,000 | 1,000 | 127,000 | 111,000 | 126,000 | 110,000 | 1,000 | 1,000 | 122,000 | -2,672,000 | 123,000 | 106,000 | -1,000 | -2,778,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of (Gain) or Loss Reclassified from AOCI to Statement of Income/within Balance Sheet: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility Operations Revenues | 3,797,000,000 | 3,814,000,000 | 10,539,000,000 | 10,412,000,000 | 0 | 0 | -1,000,000 | 0 | -1,000,000 | 0 | 0 | 0 | 756,606,000 | 776,066,000 | 2,299,587,000 | 2,161,901,000 | -4,000 | -7,000 | -75,000 | -4,000 | -53,000 | -7,000 | 537,453,000 | 499,078,000 | 1,518,357,000 | 1,371,070,000 | -10,000 | -19,000 | -173,000 | -10,000 | -89,000 | -19,000 | 959,816,000 | 1,114,339,000 | 2,710,990,000 | 3,084,657,000 | -23,000 | -47,000 | -461,000 | -23,000 | -246,000 | -47,000 | 408,803,000 | 364,851,000 | 986,008,000 | 968,683,000 | 0 | 0 | 0 | 0 | 534,196,000 | 473,391,000 | 1,324,325,000 | 1,196,753,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Revenues | 379,000,000 | 342,000,000 | 1,045,000,000 | 920,000,000 | -1,000,000 | -4,000,000 | -3,000,000 | -1,000,000 | -8,000,000 | -4,000,000 | 0 | 0 | 2,569,000 | 3,192,000 | 6,833,000 | 7,950,000 | 514,000 | 768,000 | 3,552,000 | 4,453,000 | 2,827,000 | 5,391,000 | 12,982,000 | 14,638,000 | 621,000 | 1,156,000 | 2,865,000 | 2,654,000 | 441,000 | 680,000 | 1,163,000 | 1,403,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Purchased Electricity for Resale | 373,000,000 | 327,000,000 | 1,103,000,000 | 855,000,000 | 0 | 13,000,000 | -1,000,000 | 0 | 3,000,000 | 13,000,000 | 0 | 0 | 47,391,000 | 45,196,000 | 172,334,000 | 155,421,000 | 35,000 | 411,000 | 21,000 | 35,000 | 47,000 | 411,000 | 32,976,000 | 23,399,000 | 111,602,000 | 88,797,000 | 88,000 | 1,074,000 | 47,000 | 88,000 | 115,000 | 1,074,000 | 34,568,000 | 46,146,000 | 114,911,000 | 156,384,000 | 221,000 | 2,806,000 | 129,000 | 221,000 | 309,000 | 2,806,000 | 55,915,000 | 75,719,000 | 179,405,000 | 145,983,000 | 0 | 0 | 0 | 0 | 37,505,000 | 35,109,000 | 120,273,000 | 97,150,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Operation Expense | 677,000,000 | 775,000,000 | 2,079,000,000 | 2,150,000,000 | 64,508,000 | 92,700,000 | 223,180,000 | 239,704,000 | -4,000 | -20,000 | -14,000 | -4,000 | -38,000 | -20,000 | 136,702,000 | 141,728,000 | 414,418,000 | 411,218,000 | -1,000 | -11,000 | -8,000 | -1,000 | -23,000 | -11,000 | 159,965,000 | 189,566,000 | 481,417,000 | 481,994,000 | -6,000 | -30,000 | -20,000 | -6,000 | -57,000 | -30,000 | 60,566,000 | 58,975,000 | 162,032,000 | 154,834,000 | 0 | -11,000 | -10,000 | 0 | -25,000 | -11,000 | 62,108,000 | 60,217,000 | 182,351,000 | 165,877,000 | 1,000 | -8,000 | -12,000 | 1,000 | -28,000 | -8,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maintenance Expense | 261,000,000 | 255,000,000 | 839,000,000 | 769,000,000 | 49,924,000 | 47,047,000 | 207,870,000 | 131,212,000 | 12,000 | 3,000 | -11,000 | 12,000 | -29,000 | 3,000 | 43,448,000 | 44,308,000 | 139,200,000 | 133,817,000 | 4,000 | 0 | -5,000 | 4,000 | -14,000 | 0 | 71,670,000 | 73,024,000 | 218,962,000 | 227,643,000 | 7,000 | -3,000 | -11,000 | 7,000 | -26,000 | -3,000 | 25,071,000 | 25,685,000 | 78,396,000 | 78,863,000 | 5,000 | 3,000 | -5,000 | 5,000 | -9,000 | 3,000 | 24,654,000 | 27,816,000 | 84,725,000 | 78,835,000 | 4,000 | 1,000 | -7,000 | 4,000 | -14,000 | 1,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Depreciation and Amortization Expense | 447,000,000 | 470,000,000 | 1,310,000,000 | 1,353,000,000 | 84,513,000 | 86,636,000 | 255,656,000 | 252,188,000 | 0 | 0 | 0 | 0 | 45,393,000 | 37,734,000 | 131,991,000 | 109,273,000 | 0 | 0 | 0 | 0 | 94,802,000 | 130,026,000 | 289,472,000 | 401,465,000 | 1,000 | 3,000 | 2,000 | 1,000 | 5,000 | 3,000 | 24,191,000 | 24,433,000 | 72,449,000 | 71,356,000 | 0 | 0 | 0 | 0 | 41,846,000 | 35,144,000 | 132,460,000 | 103,820,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Expense | 225,000,000 | 233,000,000 | 685,000,000 | 697,000,000 | 1,000,000 | 3,000,000 | 0 | 0 | 0 | 0 | 2,000,000 | 1,000,000 | 6,000,000 | 3,000,000 | 47,375,000 | 50,071,000 | 143,707,000 | 153,323,000 | 261,000 | 799,000 | 390,000 | 261,000 | 1,169,000 | 799,000 | 23,932,000 | 26,307,000 | 72,579,000 | 76,733,000 | 149,000 | 447,000 | 631,000 | 149,000 | 1,558,000 | 447,000 | 45,070,000 | 53,576,000 | 142,487,000 | 160,984,000 | -341,000 | -1,023,000 | -524,000 | -341,000 | -1,573,000 | -1,023,000 | 13,417,000 | 13,735,000 | 40,016,000 | 42,212,000 | -190,000 | -569,000 | -292,000 | -190,000 | -876,000 | -569,000 | 32,614,000 | 21,498,000 | 100,151,000 | 65,210,000 | 567,000 | 2,000,000 | 872,000 | 567,000 | 2,616,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | 0 | 0 | 3,000 | -9,000 | -15,000 | 3,000 | -34,000 | -9,000 | 1,000 | -6,000 | -10,000 | 1,000 | -20,000 | -6,000 | 1,000 | -15,000 | -21,000 | 1,000 | -44,000 | -15,000 | 5,000 | 1,000 | -7,000 | 5,000 | -14,000 | 1,000 | 3,000 | -3,000 | -8,000 | 3,000 | -16,000 | -3,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets | 0 | [1] | 2,000,000 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 2,000,000 | [1] | 0 | [1] | 0 | [1] | 114,000 | [1] | 1,515,000 | [1] | -190,000 | [1] | 114,000 | [1] | -9,000 | [1] | 1,515,000 | [1] | 20,000 | [1] | 265,000 | [1] | -31,000 | [1] | 20,000 | [1] | 7,000 | [1] | 265,000 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | 0 | [1] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Ending Balance in AOCI | -25,000,000 | -25,000,000 | -31,000,000 | -31,000,000 | -1,000,000 | -8,000,000 | 1,000,000 | 1,000,000 | -24,000,000 | -30,000,000 | -32,000,000 | -32,000,000 | 1,461,000 | 1,461,000 | -34,000 | -644,000 | -362,000 | -362,000 | 2,836,000 | 2,077,000 | 1,823,000 | 1,823,000 | -20,665,000 | -20,665,000 | -19,000 | -446,000 | -257,000 | -257,000 | -16,386,000 | -19,647,000 | -20,408,000 | -20,408,000 | 7,911,000 | 7,911,000 | -47,000 | -912,000 | -524,000 | -524,000 | 7,076,000 | 8,095,000 | 8,435,000 | 8,435,000 | 6,684,000 | 6,684,000 | -3,000 | 21,000 | 34,000 | 34,000 | 5,891,000 | 6,460,000 | 6,650,000 | 6,650,000 | -16,206,000 | -16,206,000 | -3,000 | 22,000 | 34,000 | 34,000 | -13,871,000 | -15,571,000 | -16,240,000 | -16,240,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Accumulated Other Comprehensive Income (Loss) Activity For Other Temporary Investments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Beginning Balance in AOCI | 3,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Changes in Fair Value Recognized in AOCI | 1,000,000 | 2,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Income | 3,000,000 | 2,000,000 | 55,000,000 | 6,000,000 | 0 | 0 | 0 | 0 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Ending Balance in AOCI | $4,000,000 | $4,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[1] | Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Rate_Matters_Details
Rate Matters (Details) (USD $) | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 25, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | |
Tanners Creek Plant, Units 1-4 [Member] | Big Sandy Plant, Unit 2 [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Storm Costs [Member] | Storm Costs [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Litigation Settlement [Member] | Litigation Settlement [Member] | Economic Development Rider [Member] | Economic Development Rider [Member] | Ormet Special Rate Recovery Mechanism [Member] | Ormet Special Rate Recovery Mechanism [Member] | Under-Recovered Capacity Costs [Member] | Under-Recovered Capacity Costs [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Electric Security Plan Filing [Member] | Storm Damage Recovery Rider [Member] | Storm Damage Recovery Rider [Member] | Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ormet Interim Arrangement [Member] | Ormet Interim Arrangement [Member] | Special Rate Mechanism For Ormet [Member] | Special Rate Mechanism For Ormet [Member] | Ohio IGCC Plant [Member] | Ohio IGCC Plant [Member] | Turk Plant [Member] | Turk Plant [Member] | Turk Plant [Member] | Turk Plant [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Texas Base Rate Case [Member] | Louisiana 2012 Formula Rate Filing [Member] | Louisiana 2012 Formula Rate Filing [Member] | Flint Creek Plant Environmental Controls [Member] | Flint Creek Plant Environmental Controls [Member] | APCo's Filing for IGCC Plant [Member] | APCo's Filing for IGCC Plant [Member] | APCo's Filing for IGCC Plant [Member] | APCo's Filing for IGCC Plant [Member] | APCo's Filing for IGCC Plant [Member] | APCo's Filing for IGCC Plant [Member] | West Virginia Expanded Net Energy Charge [Member] | West Virginia Expanded Net Energy Charge [Member] | Oklahoma Environmental Compliance Plan [Member] | Oklahoma Environmental Compliance Plan [Member] | Oklahoma Environmental Compliance Plan [Member] | Oklahoma Environmental Compliance Plan [Member] | Cook Plant Life Cycle Management Project [Member] | Cook Plant Life Cycle Management Project [Member] | Cook Plant Life Cycle Management Project [Member] | Cook Plant Life Cycle Management Project [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Virginia Generation Rate Adjustment Clause [Member] | Virginia Generation Rate Adjustment Clause [Member] | Rockport Plant Clean Coal Technology Project [Member] | Rockport Plant Clean Coal Technology Project [Member] | Rockport Plant Clean Coal Technology Project [Member] | Rockport Plant Clean Coal Technology Project [Member] | Indiana Base Rate Case [Member] | Indiana Base Rate Case [Member] | Virginia Storm Costs [Member] | Virginia Storm Costs [Member] | Kentucky 2013 Base Rate Case [Member] | ||||||
Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Deferred Wind Power Costs [Member] | Deferred Wind Power Costs [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Dresden Plant Operating Costs [Member] | Dresden Plant Operating Costs [Member] | Transmission Agreement Phase-In [Member] | Transmission Agreement Phase-In [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Rate Case Expenses [Member] | Rate Case Expenses [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Economic Development Rider [Member] | Economic Development Rider [Member] | Ormet Special Rate Recovery Mechanism [Member] | Ormet Special Rate Recovery Mechanism [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Tanners Creek Plant, Units 1-4 [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Litigation Settlement [Member] | Litigation Settlement [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Under-Recovered Capacity Costs [Member] | Under-Recovered Capacity Costs [Member] | Indiana Deferred Cook Plant Life Cycle Management Project Costs [Member] | Indiana Deferred Cook Plant Life Cycle Management Project Costs [Member] | Deferred Capacity Costs [Member] | Deferred Fuel Costs [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Significantly Excessive Earnings Test - 2010 [Member] | Significantly Excessive Earnings Test - 2010 [Member] | Storm Costs [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Electric Transmission [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Applicable to West Virginia Jurisdiction [Member] | Applicable to West Virginia Jurisdiction [Member] | Applicable to FERC Jurisdiction [Member] | Applicable to FERC Jurisdiction [Member] | Applicable to Virginia Jurisdiction [Member] | Applicable to Virginia Jurisdiction [Member] | Appalachian Power Co [Member] | Northeastern Station, Unit 3 [Member] | Northeastern Station, Unit 4 [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Indiana Michigan Power Co [Member] | Indiana Filing [Member] | Indiana Filing [Member] | Appalachian Power Co [Member] | Applicable to Virginia Jurisdiction [Member] | Applicable to Virginia Jurisdiction [Member] | Terms Of Kentucky Power Co Settlement Agreement [Member] | Terms Of Kentucky Power Co Settlement Agreement [Member] | Applicable to West Virginia and FERC Jurisdictions [Member] | Applicable to West Virginia and FERC Jurisdictions [Member] | Appalachian Power Co [Member] | Dresden Plant [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Filing [Member] | Indiana Filing [Member] | Indiana Michigan Power Co [Member] | Appalachian Power Co [Member] | |||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Deferred Capacity Costs [Member] | Deferred Fuel Costs [Member] | Subsequent Event [Member] | Ohio Power Co [Member] | Storm Costs [Member] | Electric Transmission [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Welsh Plant, Unit 2 [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Northeastern Station, Unit 3 [Member] | Northeastern Station, Unit 4 [Member] | Indiana Michigan Power Co [Member] | Appalachian Power Co [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Appalachian Power Co [Member] | Dresden Plant [Member] | Indiana Michigan Power Co [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Subsequent Event [Member] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets Not Being Recovered [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets, Noncurrent | $5,038,000,000 | $5,038,000,000 | $5,106,000,000 | $341,000,000 | $304,000,000 | $22,000,000 | $23,000,000 | $153,000,000 | $172,000,000 | $14,000,000 | $14,000,000 | $28,000,000 | $29,000,000 | $3,000,000 | $1,000,000 | $38,000,000 | $36,000,000 | $0 | $11,000,000 | $14,000,000 | $13,000,000 | $32,000,000 | $5,000,000 | $16,000,000 | $0 | $21,000,000 | $0 | $1,339,713,000 | $1,435,704,000 | $145,510,000 | $157,560,000 | $65,206,000 | $94,458,000 | $14,155,000 | $14,155,000 | $28,417,000 | $29,320,000 | $0 | $5,143,000 | $4,246,000 | $1,447,000 | $8,358,000 | $8,758,000 | $3,313,000 | $2,992,000 | $1,287,000 | $1,287,000 | $20,528,000 | $0 | $375,581,000 | $375,581,000 | $403,278,000 | $11,267,000 | $9,000,000 | $2,585,000 | $2,188,000 | $1,143,000 | $2,295,000 | $7,539,000 | $4,517,000 | $1,455,176,000 | $1,455,176,000 | $1,420,966,000 | $111,383,000 | $80,524,000 | $62,677,000 | $61,828,000 | $2,669,000 | $30,000 | $13,693,000 | $13,213,000 | $32,344,000 | $5,453,000 | $185,856,000 | $202,328,000 | $7,790,000 | $423,000 | $6,968,000 | $0 | $822,000 | $423,000 | $567,402,000 | $540,019,000 | $22,959,000 | $13,264,000 | $3,316,000 | $786,000 | $0 | $11,098,000 | $0 | $1,380,000 | $16,445,000 | $0 | $3,198,000 | $0 | $228,000,000 | $467,000,000 | $228,000,000 | $467,000,000 | $61,000,000 | $61,000,000 | $32,000,000 | $32,000,000 | $281,000,000 | $281,000,000 | $28,000,000 | $28,000,000 | $6,000,000 | $6,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Rate Matters (Textuals) [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets, Noncurrent | 5,038,000,000 | 5,038,000,000 | 5,106,000,000 | 341,000,000 | 304,000,000 | 22,000,000 | 23,000,000 | 153,000,000 | 172,000,000 | 14,000,000 | 14,000,000 | 28,000,000 | 29,000,000 | 3,000,000 | 1,000,000 | 38,000,000 | 36,000,000 | 0 | 11,000,000 | 14,000,000 | 13,000,000 | 32,000,000 | 5,000,000 | 16,000,000 | 0 | 21,000,000 | 0 | 1,339,713,000 | 1,435,704,000 | 145,510,000 | 157,560,000 | 65,206,000 | 94,458,000 | 14,155,000 | 14,155,000 | 28,417,000 | 29,320,000 | 0 | 5,143,000 | 4,246,000 | 1,447,000 | 8,358,000 | 8,758,000 | 3,313,000 | 2,992,000 | 1,287,000 | 1,287,000 | 20,528,000 | 0 | 375,581,000 | 375,581,000 | 403,278,000 | 11,267,000 | 9,000,000 | 2,585,000 | 2,188,000 | 1,143,000 | 2,295,000 | 7,539,000 | 4,517,000 | 1,455,176,000 | 1,455,176,000 | 1,420,966,000 | 111,383,000 | 80,524,000 | 62,677,000 | 61,828,000 | 2,669,000 | 30,000 | 13,693,000 | 13,213,000 | 32,344,000 | 5,453,000 | 185,856,000 | 202,328,000 | 7,790,000 | 423,000 | 6,968,000 | 0 | 822,000 | 423,000 | 567,402,000 | 540,019,000 | 22,959,000 | 13,264,000 | 3,316,000 | 786,000 | 0 | 11,098,000 | 0 | 1,380,000 | 16,445,000 | 0 | 3,198,000 | 0 | 228,000,000 | 467,000,000 | 228,000,000 | 467,000,000 | 61,000,000 | 61,000,000 | 32,000,000 | 32,000,000 | 281,000,000 | 281,000,000 | 28,000,000 | 28,000,000 | 6,000,000 | 6,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Equity Carrying Costs | 2,000,000 | 2,000,000 | 10,000,000 | 10,000,000 | 4,000,000 | 4,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Future Commitment to Support the Development of a Large Solar Farm | 20,000,000 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PUCO Ordered Refund of Pretax Earnings to Customers | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Potential Refund of Carrying Costs Due to an Accumulated Deferred Income Tax Credit | 33,000,000 | 33,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Potential Refund of Unrecognized Equity Carrying Costs Due to an Accumulated Deferred Income Tax Credit | 17,000,000 | 17,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery through May 2015 | 10.00% | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Additional Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery Beginning June 2014 through May 2015 | 50.00% | 50.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Remaining Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery from January 2015 through May 2015 | 40.00% | 40.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PUCO-Determined Fixed Price per MW Day for Customers Who Switch During ESP Period | 188.88 | 188.88 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reliability Pricing Model Rate per MW Day in Effect Through May 2014 | 33 | 33 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Stability Rider through May 2014 ($ Per MWh) | 3.5 | 3.5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | 4 | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs for the Period June 2014 through May 2015 ($ per MWh) | 1 | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Adjustment Clause as Orginially Ordered by the PUCO | 65,000,000 | 65,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Favorable Fuel Adjustment Recorded in the Second Quarter of 2012 Based on Fuel Adjustment Clause Audit Rehearing | 30,000,000 | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Remaining Retail Gain Not Already Flowed Through Fuel Adjustment Clause | 35,000,000 | 35,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Amount of Ormet's October and November 2012 Unpaid Balance Allowed to be Recovered in the Economic Development Rider | 20,000,000 | 20,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009 | 64,000,000 | 64,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009 | 2,000,000 | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Collection of Authorized Pre-Construction Costs | 24,000,000 | 24,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsidiary's Ownership Percentage | 73.00% | 73.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Impairments and Other Related Charges | 144,000,000 | 13,000,000 | 298,000,000 | 13,000,000 | 110,850,000 | 0 | 110,850,000 | 13,000,000 | 0 | 0 | 154,304,000 | 0 | 173,000,000 | 173,000,000 | 111,000,000 | 111,000,000 | 33,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | 26,172,000,000 | 26,172,000,000 | 26,279,000,000 | 5,688,679,000 | 5,632,665,000 | 3,813,995,000 | 3,813,995,000 | 3,888,230,000 | 8,392,967,000 | 8,392,967,000 | 8,673,296,000 | 1,381,290,000 | 1,346,530,000 | 4,177,462,000 | 4,062,733,000 | 1,600,000,000 | 118,000,000 | 1,600,000,000 | 118,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Incurred Construction Expenditures Before Regulatory Provision | 1,800,000,000 | 1,800,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Capitalized AFUDC and Interest Excluding Costs Attributable to its Joint Owners | 328,000,000 | 328,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Arkansas Jurisdictional Share of the Turk Plant | 20.00% | 20.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The PUCT Required Cap on the Plant, Excluding Related Transmission Costs | 1,522,000,000 | 1,522,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The PUCT Required Cap on CO2 Emission Costs (per ton) | 28 | 28 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Base Rate Increase | 83,000,000 | 83,000,000 | 114,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Return on Equity | 11.25% | 11.25% | 10.65% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Texas Jurisdictional Share of the Turk Plant | 33.00% | 33.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Base Rate Increase | 39,000,000 | 39,000,000 | 85,000,000 | 85,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Return On Equity | 9.65% | 9.65% | 10.20% | 10.20% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment, Net | 342,000,000 | 251,000,000 | 342,000,000 | 94,000,000 | 94,000,000 | 182,000,000 | 101,000,000 | 182,000,000 | 101,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Louisiana Jurisdictional Share of the Turk Plant | 29.00% | 29.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Increase in Louisiana Total Rates per the Settlement Agreement | 2,000,000 | 2,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Base Rate Increase per the Settlement Agreement | 85,000,000 | 85,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fuel Rate Decrease per the Settlement Agreement | 83,000,000 | 83,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Return on Common Equity per the Settlement Agreement | 10.00% | 10.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Projected Capital Costs | 408,000,000 | 408,000,000 | 1,200,000,000 | 1,200,000,000 | 285,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsidiary's Portion of Projected Capital Costs | 204,000,000 | 204,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commission Ordered Reduction in the Proposed Asset Transfer Price | 83,000,000 | 83,000,000 | 39,000,000 | 39,000,000 | 44,000,000 | 44,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of Deferred Preconstruction IGCC Costs for Future Recovery | 9,000,000 | 9,000,000 | 2,000,000 | 2,000,000 | 10,000,000 | 10,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Recovery of 2011 and 2012 Environmental Compliance Costs | 39,000,000 | 39,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Recommended Recovery of 2011 and 2012 Environmental Compliance Costs Per Settlement Agreement | 38,000,000 | 38,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Increase in Virginia Generation RAC Revenues Related to the Dresden Plant | 12,000,000 | 12,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Total Collection of Costs Related to the Dresden Plant | 38,000,000 | 38,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Generation RAC Per Settlement Agreement if Proposed Merger Occurs by January 2014 | 37,000,000 | 37,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Generation RAC Per Settlement Agreement if Proposed Merger Does Not Occur by January 2014 | 39,000,000 | 39,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Component to Collect Under-Recovery | 9,000,000 | 9,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Expanded Net Energy Charge Securitization | 422,000,000 | 422,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Other Expanded Net Energy Charge Related Assets | 13,000,000 | 13,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Requested Future Financing Costs | 7,000,000 | 7,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Securitization Amount Per Settlement Agreement | 376,000,000 | 376,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reduction in Annual ENEC Revenues Per Approved Settlement Agreement | 56,000,000 | 56,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Increase in Annual Construction Surcharge Per Approved Settlement Agreement | 6,000,000 | 6,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount of Deferral from the ENEC Recovery Balance Until Reaching Certain Coal Inventory Levels | 21,000,000 | 21,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Expanded Net Energy Charge Related Assets | 14,000,000 | 14,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Write-off of Regulatory Asset, Pretax | 30,000,000 | 30,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Approved Base Rate Increase Adjustment | 92,000,000 | 92,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Amount Excluded from Indiana Utility Regulatory Commission LCM Project Approval | 23,000,000 | 23,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revised Projected Capital Costs per Settlement Agreement | 258,000,000 | 129,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Federal Mandate Percentage of Project to be Recovered Under a Rider per Settlement Agreement | 80.00% | 80.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Percentage of Project to be Deferred and Recovered in a Future Rate Case per Settlement Agreement | 20.00% | 20.00% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Construction Work in Progress | 2,489,000,000 | 2,489,000,000 | 1,819,000,000 | 250,040,000 | 266,247,000 | 223,860,000 | 223,860,000 | 99,783,000 | 440,199,000 | 440,199,000 | 354,497,000 | 118,879,000 | 95,170,000 | 388,835,000 | 341,063,000 | 285,000,000 | 285,000,000 | 93,000,000 | 48,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual Amount of Asset Transfer Rider | 44,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Annual Level of Off System Sales Margins in Base Rates Above Which is Proposed to be Retained by Kentucky Power Company | 15,300,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Deferred Charges and Other Noncurrent Assets | $1,414,000,000 | $1,414,000,000 | $1,627,000,000 | $96,016,000 | $115,078,000 | $81,848,000 | $81,848,000 | $76,432,000 | $133,024,000 | $133,024,000 | $320,026,000 | $17,217,000 | $8,560,000 | $87,016,000 | $111,364,000 |
Commitments_Guarantees_and_Con2
Commitments, Guarantees and Contingencies (Details) (USD $) | 9 Months Ended |
Sep. 30, 2013 | |
Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | $185,000,000 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 402,000,000 |
Bilateral Letters of Credit | 407,000,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Revolving Credit Facilities | 3,500,000,000 |
Letters of Credit Limit | 1,200,000,000 |
Maximum Future Payments for Letters of Credit | 185,000,000 |
Variable Rate PCBs Supported | 402,000,000 |
Bilateral Letters of Credit | 407,000,000 |
Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 20,000,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 20,000,000 |
Guarantees of Third Party Obligations [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Guarantees of Mine Reclamation, Amount | 115,000,000 |
Estimated Final Cost Mine Reclamation | 58,000,000 |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 63,000,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 13,000,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 50,000,000 |
Indiana Michigan Power Co [Member] | Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | 150,000 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 77,000,000 |
Bilateral Letters of Credit | 77,886,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Maximum Future Payments for Letters of Credit | 150,000 |
Variable Rate PCBs Supported | 77,000,000 |
Bilateral Letters of Credit | 77,886,000 |
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,481,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,481,000 |
Future Minimum Lease Obligation for Remaining Railcars | 14,000,000 |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term | 83.00% |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term | 77.00% |
Maximum Potential Loss on Guarantee of Return-and-Sale Option | 9,000,000 |
Southwestern Electric Power Co [Member] | Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | 4,448,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Maximum Future Payments for Letters of Credit | 4,448,000 |
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,441,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 2,441,000 |
Future Minimum Lease Obligation for Remaining Railcars | 15,000,000 |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term | 83.00% |
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term | 77.00% |
Maximum Potential Loss on Guarantee of Return-and-Sale Option | 10,000,000 |
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Guarantees of Mine Reclamation, Amount | 115,000,000 |
Estimated Final Cost Mine Reclamation | 58,000,000 |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 63,000,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 13,000,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 50,000,000 |
Ohio Power Co [Member] | Letters of Credit [Member] | |
Maximum Future Payments for Letters of Credit [Abstract] | |
Maximum Future Payments for Letters of Credit | 3,081,000 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 50,000,000 |
Bilateral Letters of Credit | 50,575,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Maximum Future Payments for Letters of Credit | 3,081,000 |
Variable Rate PCBs Supported | 50,000,000 |
Bilateral Letters of Credit | 50,575,000 |
Ohio Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 4,505,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 4,505,000 |
Appalachian Power Co [Member] | Letters of Credit [Member] | |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | |
Variable Rate PCBs Supported | 229,650,000 |
Bilateral Letters of Credit | 232,293,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Variable Rate PCBs Supported | 229,650,000 |
Bilateral Letters of Credit | 232,293,000 |
Appalachian Power Co [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,630,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 3,630,000 |
Public Service Co Of Oklahoma [Member] | Master Lease Agreements [Member] | |
Maximum Potential Loss on Master Lease Agreements [Abstract] | |
Max Potential Loss on Master Lease Agreements | 1,204,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Max Potential Loss on Master Lease Agreements | 1,204,000 |
Superfund and State Remediation [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Expense Recorded Due to Remediation Work Remaining Provision | 10,000,000 |
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Expense Recorded Due to Remediation Work Remaining Provision | 10,000,000 |
Alaskan Villages Claim [Member] | From [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Amount Required for Relocation of the Village | 95,000,000 |
Alaskan Villages Claim [Member] | To [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Amount Required for Relocation of the Village | 400,000,000 |
Nuclear Incident Liability [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Insurance Coverage for Property Damage, Decommissioning and Decontamination | 2,800,000,000 |
Purchases Coverage for Property Damage for a Nonnuclear Incident | 1,700,000,000 |
Nuclear Incident Liability [Member] | Indiana Michigan Power Co [Member] | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | |
Insurance Coverage for Property Damage, Decommissioning and Decontamination | 2,800,000,000 |
Purchases Coverage for Property Damage for a Nonnuclear Incident | $1,700,000,000 |
Acquisitions_Dispositions_and_
Acquisitions Dispositions and Discontinued Operations (Details) (USD $) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Acquisitions of Assets | $6,000,000 | $89,000,000 | |||
Goodwill | 91,000,000 | 91,000,000 | 91,000,000 | ||
Asset Impairments and Other Related Charges | 144,000,000 | 13,000,000 | 298,000,000 | 13,000,000 | |
Utility Operations [Member] | Muskingum River Plant Unit 5 [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 154,000,000 | ||||
Asset Impairment on Related Material and Supplies Inventory | 6,000,000 | 6,000,000 | |||
Fair Value of MR5 Generating Unit | 0 | 0 | |||
Utility Operations [Member] | Turk Plant [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 111,000,000 | 13,000,000 | |||
Utility Operations [Member] | Big Sandy Plant Unit 2 FGD Project [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 33,000,000 | ||||
Nonutility Operations - Generation and Marketing [Member] | BlueStar Energy [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Acquisitions of Assets | 70,000,000 | ||||
Goodwill | 15,000,000 | 15,000,000 | |||
Intangible Assets Associated with Sales Contracts and Customer Accounts | 58,000,000 | ||||
Liabilities Associated with Supply Contracts | 25,000,000 | ||||
Southwestern Electric Power Co [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 110,850,000 | 0 | 110,850,000 | 13,000,000 | |
Southwestern Electric Power Co [Member] | Turk Plant [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 111,000,000 | 13,000,000 | |||
Ohio Power Co [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 0 | 0 | 154,304,000 | 0 | |
Ohio Power Co [Member] | Muskingum River Plant Unit 5 [Member] | |||||
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | |||||
Asset Impairments and Other Related Charges | 154,000,000 | ||||
Asset Impairment on Related Material and Supplies Inventory | 6,000,000 | 6,000,000 | |||
Fair Value of MR5 Generating Unit | $0 | $0 |
Benefit_Plans_Details
Benefit Plans (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 |
Pension Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | $17,000 | $19,000 | $52,000 | $57,000 |
Interest Cost | 51,000 | 56,000 | 152,000 | 167,000 |
Expected Return on Plan Assets | -69,000 | -80,000 | -208,000 | -239,000 |
Amortization of Transition Obligation | 0 | 0 | 0 | 0 |
Amortization of Prior Service Cost (Credit) | 1,000 | 0 | 2,000 | 0 |
Amortization of Net Actuarial Loss | 45,000 | 42,000 | 137,000 | 117,000 |
Net Periodic Benefit Cost (Credit) | 45,000 | 37,000 | 135,000 | 102,000 |
Pension Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,543 | 1,892 | 4,628 | 5,674 |
Interest Cost | 6,916 | 7,553 | 20,747 | 22,659 |
Expected Return on Plan Assets | -9,260 | -10,486 | -27,780 | -31,458 |
Amortization of Transition Obligation | 0 | 0 | 0 | 0 |
Amortization of Prior Service Cost (Credit) | 49 | 118 | 148 | 356 |
Amortization of Net Actuarial Loss | 6,256 | 5,085 | 18,769 | 15,254 |
Net Periodic Benefit Cost (Credit) | 5,504 | 4,162 | 16,512 | 12,485 |
Pension Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2,183 | 2,477 | 6,551 | 7,431 |
Interest Cost | 6,025 | 6,562 | 18,075 | 19,684 |
Expected Return on Plan Assets | -8,206 | -9,392 | -24,619 | -28,175 |
Amortization of Transition Obligation | 0 | 0 | 0 | 0 |
Amortization of Prior Service Cost (Credit) | 49 | 101 | 146 | 305 |
Amortization of Net Actuarial Loss | 5,422 | 4,392 | 16,266 | 13,177 |
Net Periodic Benefit Cost (Credit) | 5,473 | 4,140 | 16,419 | 12,422 |
Pension Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2,362 | 2,751 | 7,107 | 8,253 |
Interest Cost | 10,268 | 11,298 | 30,852 | 33,895 |
Expected Return on Plan Assets | -15,103 | -17,100 | -45,386 | -51,301 |
Amortization of Transition Obligation | 0 | 0 | 0 | 0 |
Amortization of Prior Service Cost (Credit) | 71 | 186 | 212 | 557 |
Amortization of Net Actuarial Loss | 9,287 | 7,610 | 27,905 | 22,830 |
Net Periodic Benefit Cost (Credit) | 6,885 | 4,745 | 20,690 | 14,234 |
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,391 | 1,487 | 4,172 | 4,463 |
Interest Cost | 2,748 | 3,076 | 8,245 | 9,226 |
Expected Return on Plan Assets | -3,919 | -4,503 | -11,756 | -13,511 |
Amortization of Prior Service Cost (Credit) | 75 | -237 | 223 | -711 |
Amortization of Net Actuarial Loss | 2,461 | 2,051 | 7,383 | 6,154 |
Net Periodic Benefit Cost (Credit) | 2,756 | 1,874 | 8,267 | 5,621 |
Pension Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,752 | 1,775 | 5,258 | 5,324 |
Interest Cost | 2,864 | 3,134 | 8,591 | 9,403 |
Expected Return on Plan Assets | -4,126 | -4,717 | -12,381 | -14,150 |
Amortization of Prior Service Cost (Credit) | 87 | -198 | 262 | -595 |
Amortization of Net Actuarial Loss | 2,553 | 2,083 | 7,660 | 6,248 |
Net Periodic Benefit Cost (Credit) | 3,130 | 2,077 | 9,390 | 6,230 |
Other Postretirement Benefit Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 5,000 | 12,000 | 17,000 | 35,000 |
Interest Cost | 18,000 | 26,000 | 53,000 | 78,000 |
Expected Return on Plan Assets | -27,000 | -26,000 | -80,000 | -76,000 |
Amortization of Transition Obligation | 0 | 1,000 | 0 | 1,000 |
Amortization of Prior Service Cost (Credit) | -17,000 | -5,000 | -52,000 | -14,000 |
Amortization of Net Actuarial Loss | 16,000 | 14,000 | 48,000 | 43,000 |
Net Periodic Benefit Cost (Credit) | -5,000 | 22,000 | -14,000 | 67,000 |
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 641 | 1,346 | 1,924 | 4,040 |
Interest Cost | 3,363 | 4,616 | 10,090 | 13,847 |
Expected Return on Plan Assets | -4,537 | -4,188 | -13,610 | -12,564 |
Amortization of Transition Obligation | 0 | 201 | 0 | 601 |
Amortization of Prior Service Cost (Credit) | -2,512 | -716 | -7,537 | -2,147 |
Amortization of Net Actuarial Loss | 3,063 | 2,631 | 9,187 | 7,894 |
Net Periodic Benefit Cost (Credit) | 18 | 3,890 | 54 | 11,671 |
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 804 | 1,655 | 2,414 | 4,965 |
Interest Cost | 2,056 | 3,196 | 6,166 | 9,589 |
Expected Return on Plan Assets | -3,295 | -3,212 | -9,887 | -9,635 |
Amortization of Transition Obligation | 0 | 33 | 0 | 99 |
Amortization of Prior Service Cost (Credit) | -2,356 | -595 | -7,066 | -1,787 |
Amortization of Net Actuarial Loss | 1,882 | 1,762 | 5,645 | 5,287 |
Net Periodic Benefit Cost (Credit) | -909 | 2,839 | -2,728 | 8,518 |
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1,028 | 2,187 | 3,627 | 6,561 |
Interest Cost | 4,100 | 6,047 | 12,994 | 18,142 |
Expected Return on Plan Assets | -6,221 | -5,639 | -18,698 | -16,917 |
Amortization of Transition Obligation | 0 | 26 | 0 | 78 |
Amortization of Prior Service Cost (Credit) | -3,219 | -969 | -9,680 | -2,905 |
Amortization of Net Actuarial Loss | 3,761 | 3,418 | 11,843 | 10,252 |
Net Periodic Benefit Cost (Credit) | -551 | 5,070 | 86 | 15,211 |
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 343 | 709 | 1,029 | 2,127 |
Interest Cost | 948 | 1,449 | 2,844 | 4,348 |
Expected Return on Plan Assets | -1,522 | -1,480 | -4,566 | -4,441 |
Amortization of Prior Service Cost (Credit) | -1,072 | -270 | -3,217 | -809 |
Amortization of Net Actuarial Loss | 869 | 797 | 2,607 | 2,391 |
Net Periodic Benefit Cost (Credit) | -434 | 1,205 | -1,303 | 3,616 |
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 424 | 831 | 1,270 | 2,493 |
Interest Cost | 1,075 | 1,669 | 3,226 | 5,005 |
Expected Return on Plan Assets | -1,720 | -1,699 | -5,160 | -5,096 |
Amortization of Prior Service Cost (Credit) | -1,289 | -234 | -3,867 | -700 |
Amortization of Net Actuarial Loss | 982 | 915 | 2,946 | 2,744 |
Net Periodic Benefit Cost (Credit) | ($528) | $1,482 | ($1,585) | $4,446 |
Business_Segments_Details
Business Segments (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||||
In Thousands, unless otherwise specified | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | |||||
Reportable Segment Information | ||||||||||
Revenues | $4,176,000 | $4,156,000 | $11,584,000 | $11,332,000 | ||||||
NET INCOME (LOSS) | 434,000 | 488,000 | 1,137,000 | 1,241,000 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 59,044,000 | 59,044,000 | 57,454,000 | |||||||
Accumulated Depreciation and Amortization | 19,174,000 | 19,174,000 | 18,691,000 | |||||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 39,870,000 | 39,870,000 | 38,763,000 | |||||||
Total Assets | 54,963,000 | 54,963,000 | 54,367,000 | |||||||
Reconciling Adjustments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | -57,000 | -44,000 | -150,000 | -108,000 | ||||||
NET INCOME (LOSS) | 0 | 0 | 0 | 0 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | -269,000 | [1] | -269,000 | [1] | -266,000 | [1] | ||||
Accumulated Depreciation and Amortization | -82,000 | [1] | -82,000 | [1] | -71,000 | [1] | ||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | -187,000 | [1] | -187,000 | [1] | -195,000 | [1] | ||||
Total Assets | -17,977,000 | [1],[2] | -17,977,000 | [1],[2] | -17,192,000 | [1],[2] | ||||
Utility Operations [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 3,788,000 | 3,811,000 | 10,520,000 | 10,407,000 | ||||||
NET INCOME (LOSS) | 409,000 | 471,000 | 980,000 | 1,220,000 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 56,745,000 | 56,745,000 | 55,707,000 | |||||||
Accumulated Depreciation and Amortization | 18,791,000 | 18,791,000 | 18,344,000 | |||||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 37,954,000 | 37,954,000 | 37,363,000 | |||||||
Total Assets | 51,598,000 | 51,598,000 | 51,477,000 | |||||||
Utility Operations [Member] | Operating Segments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 3,819,000 | 3,839,000 | 10,614,000 | 10,482,000 | ||||||
Utility Operations [Member] | Significant Reconciling Items [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 31,000 | 28,000 | 94,000 | 75,000 | ||||||
Transmission Operations [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 8,000 | 3,000 | 18,000 | 5,000 | ||||||
NET INCOME (LOSS) | 22,000 | 14,000 | 53,000 | 31,000 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 1,296,000 | 1,296,000 | 748,000 | |||||||
Accumulated Depreciation and Amortization | 7,000 | 7,000 | 4,000 | |||||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 1,289,000 | 1,289,000 | 744,000 | |||||||
Total Assets | 1,809,000 | 1,809,000 | 1,216,000 | |||||||
Transmission Operations [Member] | Operating Segments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 26,000 | 10,000 | 53,000 | 15,000 | ||||||
Transmission Operations [Member] | Significant Reconciling Items [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 18,000 | 7,000 | 35,000 | 10,000 | ||||||
Nonutility Operations - AEP River Operations [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 125,000 | 142,000 | 365,000 | 477,000 | ||||||
NET INCOME (LOSS) | -1,000 | -1,000 | -12,000 | 11,000 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 637,000 | 637,000 | 636,000 | |||||||
Accumulated Depreciation and Amortization | 182,000 | 182,000 | 161,000 | |||||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 455,000 | 455,000 | 475,000 | |||||||
Total Assets | 650,000 | 650,000 | 670,000 | |||||||
Nonutility Operations - AEP River Operations [Member] | Operating Segments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 130,000 | 147,000 | 380,000 | 493,000 | ||||||
Nonutility Operations - AEP River Operations [Member] | Significant Reconciling Items [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 5,000 | 5,000 | 15,000 | 16,000 | ||||||
Nonutility Operations - Generation and Marketing [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 251,000 | 194,000 | 671,000 | 427,000 | ||||||
NET INCOME (LOSS) | 4,000 | 10,000 | 15,000 | 4,000 | ||||||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 627,000 | 627,000 | 621,000 | |||||||
Accumulated Depreciation and Amortization | 268,000 | 268,000 | 246,000 | |||||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 359,000 | 359,000 | 375,000 | |||||||
Total Assets | 1,009,000 | 1,009,000 | 1,005,000 | |||||||
Nonutility Operations - Generation and Marketing [Member] | Operating Segments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 251,000 | 194,000 | 671,000 | 427,000 | ||||||
Nonutility Operations - Generation and Marketing [Member] | Significant Reconciling Items [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 0 | 0 | 0 | 0 | ||||||
All Other [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 4,000 | [3] | 6,000 | [3] | 10,000 | [3] | 16,000 | [3] | ||
NET INCOME (LOSS) | 0 | [3] | -6,000 | [3] | 101,000 | [3] | -25,000 | [3] | ||
Balance Sheet Information | ||||||||||
Total Property, Plant and Equipment | 8,000 | [3] | 8,000 | [3] | 8,000 | [3] | ||||
Accumulated Depreciation and Amortization | 8,000 | [3] | 8,000 | [3] | 7,000 | [3] | ||||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 0 | [3] | 0 | [3] | 1,000 | [3] | ||||
Total Assets | 17,874,000 | [3] | 17,874,000 | [3] | 17,191,000 | [3] | ||||
All Other [Member] | Operating Segments [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | 7,000 | [3] | 10,000 | [3] | 16,000 | [3] | 23,000 | [3] | ||
All Other [Member] | Significant Reconciling Items [Member] | ||||||||||
Reportable Segment Information | ||||||||||
Revenues | $3,000 | [3] | $4,000 | [3] | $6,000 | [3] | $7,000 | [3] | ||
[1] | Includes eliminations due to an intercompany capital lease. | |||||||||
[2] | Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies. | |||||||||
[3] | All Other includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. |
Derivatives_and_Hedging_Detail
Derivatives and Hedging (Details) (USD $) | 3 Months Ended | 9 Months Ended | 12 Months Ended | |||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | $5,000,000 | $5,000,000 | $7,000,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 26,000,000 | 26,000,000 | 50,000,000 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 171,000,000 | 171,000,000 | 191,000,000 | |||||||
Long-term Risk Management Assets | 314,000,000 | 314,000,000 | 368,000,000 | |||||||
Total Assets | 485,000,000 | 485,000,000 | 559,000,000 | |||||||
Current Risk Management Liabilities | 102,000,000 | 102,000,000 | 155,000,000 | |||||||
Long-term Risk Management Liabilities | 182,000,000 | 182,000,000 | 214,000,000 | |||||||
Total Liabilities | 284,000,000 | 284,000,000 | 369,000,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 8,000,000 | 13,000,000 | 43,000,000 | 24,000,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 9,000,000 | [1] | 9,000,000 | [1] | 24,000,000 | [1] | ||||
Hedging Liabilities | 13,000,000 | [1] | 13,000,000 | [1] | 73,000,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -25,000,000 | -25,000,000 | -38,000,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -6,000,000 | -12,000,000 | ||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 27 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 3,000,000 | 3,000,000 | 7,000,000 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 39,000,000 | 39,000,000 | 32,000,000 | |||||||
Amount Attributable to RTO and ISO Activities | 38,000,000 | 38,000,000 | 31,000,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 341,000,000 | 341,000,000 | 469,000,000 | |||||||
Amount of Cash Collateral Posted | 1,000,000 | 1,000,000 | 8,000,000 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 258,000,000 | 258,000,000 | 328,000,000 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 5,000,000 | 5,000,000 | 7,000,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 26,000,000 | 26,000,000 | 50,000,000 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 27 months | |||||||||
Gain (Loss) on Fair Value Hedging Instrument | 4,000,000 | 1,000,000 | -8,000,000 | 3,000,000 | ||||||
Gain (Loss) on Fair Value Portion of Long Term Debt | -4,000,000 | -1,000,000 | 8,000,000 | -3,000,000 | ||||||
Appalachian Power Co [Member] | ||||||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 116,000 | 116,000 | 1,262,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 5,608,000 | 5,608,000 | 11,029,000 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 24,550,000 | 24,550,000 | 30,960,000 | |||||||
Long-term Risk Management Assets | 20,839,000 | 20,839,000 | 34,360,000 | |||||||
Total Assets | 45,389,000 | 45,389,000 | 65,320,000 | |||||||
Current Risk Management Liabilities | 11,641,000 | 11,641,000 | 16,698,000 | |||||||
Long-term Risk Management Liabilities | 12,081,000 | 12,081,000 | 18,476,000 | |||||||
Total Liabilities | 23,722,000 | 23,722,000 | 35,174,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -204,000 | -1,432,000 | 459,000 | 1,485,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 850,000 | 850,000 | 2,159,000 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 6,183,000 | 6,183,000 | 3,699,000 | |||||||
Amount Attributable to RTO and ISO Activities | 5,812,000 | 5,812,000 | 3,510,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 27,044,000 | 27,044,000 | 49,465,000 | |||||||
Amount of Cash Collateral Posted | 0 | 0 | 1,822,000 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 22,162,000 | 22,162,000 | 30,160,000 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 116,000 | 116,000 | 1,262,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 5,608,000 | 5,608,000 | 11,029,000 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Indiana Michigan Power Co [Member] | ||||||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 76,000 | 76,000 | 867,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 3,688,000 | 3,688,000 | 7,576,000 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 16,150,000 | 16,150,000 | 26,974,000 | |||||||
Long-term Risk Management Assets | 13,733,000 | 13,733,000 | 23,569,000 | |||||||
Total Assets | 29,883,000 | 29,883,000 | 50,543,000 | |||||||
Current Risk Management Liabilities | 9,268,000 | 9,268,000 | 31,517,000 | |||||||
Long-term Risk Management Liabilities | 8,307,000 | 8,307,000 | 13,898,000 | |||||||
Total Liabilities | 17,575,000 | 17,575,000 | 45,415,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -1,954,000 | -2,666,000 | -1,271,000 | 3,829,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 560,000 | 560,000 | 1,483,000 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 4,069,000 | 4,069,000 | 2,540,000 | |||||||
Amount Attributable to RTO and ISO Activities | 3,824,000 | 3,824,000 | 2,411,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 17,796,000 | 17,796,000 | 53,499,000 | |||||||
Amount of Cash Collateral Posted | 0 | 0 | 1,252,000 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 14,583,000 | 14,583,000 | 40,240,000 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 76,000 | 76,000 | 867,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 3,688,000 | 3,688,000 | 7,576,000 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Ohio Power Co [Member] | ||||||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 159,000 | 159,000 | 1,774,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 7,693,000 | 7,693,000 | 15,500,000 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 34,178,000 | 34,178,000 | 44,313,000 | |||||||
Long-term Risk Management Assets | 28,594,000 | 28,594,000 | 48,288,000 | |||||||
Total Assets | 62,772,000 | 62,772,000 | 92,601,000 | |||||||
Current Risk Management Liabilities | 16,431,000 | 16,431,000 | 24,155,000 | |||||||
Long-term Risk Management Liabilities | 16,577,000 | 16,577,000 | 25,965,000 | |||||||
Total Liabilities | 33,008,000 | 33,008,000 | 50,120,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -1,198,000 | -3,701,000 | -2,000 | 2,482,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 1,167,000 | 1,167,000 | 3,034,000 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 8,484,000 | 8,484,000 | 5,198,000 | |||||||
Amount Attributable to RTO and ISO Activities | 7,975,000 | 7,975,000 | 4,933,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 37,110,000 | 37,110,000 | 69,516,000 | |||||||
Amount of Cash Collateral Posted | 0 | 0 | 2,561,000 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 30,410,000 | 30,410,000 | 42,386,000 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 159,000 | 159,000 | 1,774,000 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 7,693,000 | 7,693,000 | 15,500,000 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 7,000 | 7,000 | 0 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 852,000 | 852,000 | 509,000 | |||||||
Long-term Risk Management Assets | 149,000 | 149,000 | 31,000 | |||||||
Total Assets | 1,001,000 | 1,001,000 | 540,000 | |||||||
Current Risk Management Liabilities | 1,388,000 | 1,388,000 | 5,848,000 | |||||||
Long-term Risk Management Liabilities | 0 | 0 | 31,000 | |||||||
Total Liabilities | 1,388,000 | 1,388,000 | 5,879,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,003,000 | 671,000 | 3,421,000 | -5,126,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 0 | 0 | 0 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 255,000 | 255,000 | 1,509,000 | |||||||
Amount Attributable to RTO and ISO Activities | 200,000 | 200,000 | 1,429,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 5,000 | 5,000 | 0 | |||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 5,000 | 5,000 | 0 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 7,000 | 7,000 | 0 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Southwestern Electric Power Co [Member] | ||||||||||
Cash Collateral Netting | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 8,000 | 8,000 | 0 | |||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 402,000 | 402,000 | 695,000 | |||||||
Long-term Risk Management Assets | 21,000 | 21,000 | 0 | |||||||
Total Assets | 423,000 | 423,000 | 695,000 | |||||||
Current Risk Management Liabilities | 296,000 | 296,000 | 1,128,000 | |||||||
Total Liabilities | 296,000 | 296,000 | 1,128,000 | |||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 602,000 | 300,000 | 965,000 | -6,545,000 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Collateral Triggering Events [Abstract] | ||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 0 | 0 | 0 | |||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 315,000 | 315,000 | 1,778,000 | |||||||
Amount Attributable to RTO and ISO Activities | 247,000 | 247,000 | 1,683,000 | |||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 6,000 | 6,000 | 0 | |||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | |||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 6,000 | 6,000 | 0 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0 | |||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 8,000 | 8,000 | 0 | |||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 15 months | |||||||||
Risk Management Contracts [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 462,000,000 | [2],[3] | 462,000,000 | [2],[3] | 517,000,000 | [2],[4] | ||||
Total Liabilities | 259,000,000 | [2],[3] | 259,000,000 | [2],[3] | 292,000,000 | [2],[4] | ||||
Risk Management Contracts [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 45,082,000 | [2],[5] | 45,082,000 | [2],[5] | 65,018,000 | [2],[5] | ||||
Total Liabilities | 23,292,000 | [2],[5] | 23,292,000 | [2],[5] | 33,819,000 | [2],[5] | ||||
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 29,684,000 | [2],[5] | 29,684,000 | [2],[5] | 50,343,000 | [2],[5] | ||||
Total Liabilities | 17,297,000 | [2],[5] | 17,297,000 | [2],[5] | 24,960,000 | [2],[5] | ||||
Risk Management Contracts [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 62,354,000 | [2],[5] | 62,354,000 | [2],[5] | 92,185,000 | [2],[5] | ||||
Total Liabilities | 32,423,000 | [2],[5] | 32,423,000 | [2],[5] | 48,217,000 | [2],[5] | ||||
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 991,000 | [2],[5] | 991,000 | [2],[5] | 515,000 | [2],[5] | ||||
Total Liabilities | 1,372,000 | [2],[5] | 1,372,000 | [2],[5] | 5,879,000 | [2],[5] | ||||
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Total Assets | 411,000 | [2],[5] | 411,000 | [2],[5] | 671,000 | [2],[5] | ||||
Total Liabilities | 277,000 | [2],[5] | 277,000 | [2],[5] | 1,128,000 | [2],[5] | ||||
Commodity [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 9,000,000 | [1] | 9,000,000 | [1] | 24,000,000 | [1] | ||||
Hedging Liabilities | 11,000,000 | [1] | 11,000,000 | [1] | 36,000,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -1,000,000 | -1,000,000 | -8,000,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -2,000,000 | -8,000,000 | ||||||||
Derivatives and Hedging (Textuals) [Abstract] | ||||||||||
Cross Default Provisions Maximum Third Party Obligation Amount | 50,000,000 | 50,000,000 | 50,000,000 | |||||||
Commodity [Member] | Appalachian Power Co [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 307,000 | [1] | 307,000 | [1] | 302,000 | [1] | ||||
Hedging Liabilities | 430,000 | [1] | 430,000 | [1] | 1,355,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -34,000 | -34,000 | -644,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -172,000 | -507,000 | ||||||||
Commodity [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 199,000 | [1] | 199,000 | [1] | 200,000 | [1] | ||||
Hedging Liabilities | 278,000 | [1] | 278,000 | [1] | 931,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -19,000 | -19,000 | -446,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -113,000 | -355,000 | ||||||||
Commodity [Member] | Ohio Power Co [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 418,000 | [1] | 418,000 | [1] | 416,000 | [1] | ||||
Hedging Liabilities | 585,000 | [1] | 585,000 | [1] | 1,903,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -47,000 | -47,000 | -912,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -236,000 | -720,000 | ||||||||
Commodity [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 10,000 | [1] | 10,000 | [1] | 25,000 | [1] | ||||
Hedging Liabilities | 16,000 | [1] | 16,000 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -3,000 | -3,000 | 21,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,000 | 21,000 | ||||||||
Commodity [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 12,000 | [1] | 12,000 | [1] | 24,000 | [1] | ||||
Hedging Liabilities | 19,000 | [1] | 19,000 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -3,000 | -3,000 | 22,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,000 | 22,000 | ||||||||
Commodity [Member] | Risk Management Contracts [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 441,000,000 | [6] | 441,000,000 | [6] | 589,000,000 | [6] | ||||
Long-term Risk Management Assets | 433,000,000 | [6] | 433,000,000 | [6] | 528,000,000 | [6] | ||||
Total Assets | 874,000,000 | [6] | 874,000,000 | [6] | 1,117,000,000 | [6] | ||||
Current Risk Management Liabilities | 389,000,000 | [6] | 389,000,000 | [6] | 546,000,000 | [6] | ||||
Long-term Risk Management Liabilities | 301,000,000 | [6] | 301,000,000 | [6] | 383,000,000 | [6] | ||||
Total Liabilities | 690,000,000 | [6] | 690,000,000 | [6] | 929,000,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 184,000,000 | [6] | 184,000,000 | [6] | 188,000,000 | [6] | ||||
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 68,593,000 | [6] | 68,593,000 | [6] | 127,645,000 | [6] | ||||
Long-term Risk Management Assets | 32,501,000 | [6] | 32,501,000 | [6] | 60,498,000 | [6] | ||||
Total Assets | 101,094,000 | [6] | 101,094,000 | [6] | 188,143,000 | [6] | ||||
Current Risk Management Liabilities | 59,793,000 | [6] | 59,793,000 | [6] | 119,430,000 | [6] | ||||
Long-term Risk Management Liabilities | 25,003,000 | [6] | 25,003,000 | [6] | 47,281,000 | [6] | ||||
Total Liabilities | 84,796,000 | [6] | 84,796,000 | [6] | 166,711,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 16,298,000 | [6] | 16,298,000 | [6] | 21,432,000 | [6] | ||||
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 44,988,000 | [6] | 44,988,000 | [6] | 93,268,000 | [6] | ||||
Long-term Risk Management Assets | 21,432,000 | [6] | 21,432,000 | [6] | 41,553,000 | [6] | ||||
Total Assets | 66,420,000 | [6] | 66,420,000 | [6] | 134,821,000 | [6] | ||||
Current Risk Management Liabilities | 40,809,000 | [6] | 40,809,000 | [6] | 82,433,000 | [6] | ||||
Long-term Risk Management Liabilities | 16,836,000 | [6] | 16,836,000 | [6] | 33,714,000 | [6] | ||||
Total Liabilities | 57,645,000 | [6] | 57,645,000 | [6] | 116,147,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 8,775,000 | [6] | 8,775,000 | [6] | 18,674,000 | [6] | ||||
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 96,628,000 | [6] | 96,628,000 | [6] | 183,064,000 | [6] | ||||
Long-term Risk Management Assets | 44,597,000 | [6] | 44,597,000 | [6] | 85,023,000 | [6] | ||||
Total Assets | 141,225,000 | [6] | 141,225,000 | [6] | 268,087,000 | [6] | ||||
Current Risk Management Liabilities | 84,519,000 | [6] | 84,519,000 | [6] | 171,397,000 | [6] | ||||
Long-term Risk Management Liabilities | 34,309,000 | [6] | 34,309,000 | [6] | 66,448,000 | [6] | ||||
Total Liabilities | 118,828,000 | [6] | 118,828,000 | [6] | 237,845,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 22,397,000 | [6] | 22,397,000 | [6] | 30,242,000 | [6] | ||||
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 1,394,000 | [6] | 1,394,000 | [6] | 1,657,000 | [6] | ||||
Long-term Risk Management Assets | 149,000 | [6] | 149,000 | [6] | 0 | [6] | ||||
Total Assets | 1,543,000 | [6] | 1,543,000 | [6] | 1,657,000 | [6] | ||||
Current Risk Management Liabilities | 1,931,000 | [6] | 1,931,000 | [6] | 7,021,000 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 1,931,000 | [6] | 1,931,000 | [6] | 7,021,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -388,000 | [6] | -388,000 | [6] | -5,364,000 | [6] | ||||
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 1,444,000 | [6] | 1,444,000 | [6] | 2,804,000 | [6] | ||||
Long-term Risk Management Assets | 21,000 | [6] | 21,000 | [6] | 0 | [6] | ||||
Total Assets | 1,465,000 | [6] | 1,465,000 | [6] | 2,804,000 | [6] | ||||
Current Risk Management Liabilities | 1,339,000 | [6] | 1,339,000 | [6] | 3,261,000 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 1,339,000 | [6] | 1,339,000 | [6] | 3,261,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 126,000 | [6] | 126,000 | [6] | -457,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 19,000,000 | [6] | 19,000,000 | [6] | 32,000,000 | [6] | ||||
Long-term Risk Management Assets | 6,000,000 | [6] | 6,000,000 | [6] | 5,000,000 | [6] | ||||
Total Assets | 25,000,000 | [6] | 25,000,000 | [6] | 37,000,000 | [6] | ||||
Current Risk Management Liabilities | 23,000,000 | [6] | 23,000,000 | [6] | 43,000,000 | [6] | ||||
Long-term Risk Management Liabilities | 4,000,000 | [6] | 4,000,000 | [6] | 6,000,000 | [6] | ||||
Total Liabilities | 27,000,000 | [6] | 27,000,000 | [6] | 49,000,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -2,000,000 | [6] | -2,000,000 | [6] | -12,000,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 233,000 | [6] | 233,000 | [6] | 338,000 | [6] | ||||
Long-term Risk Management Assets | 226,000 | [6] | 226,000 | [6] | 215,000 | [6] | ||||
Total Assets | 459,000 | [6] | 459,000 | [6] | 553,000 | [6] | ||||
Current Risk Management Liabilities | 567,000 | [6] | 567,000 | [6] | 1,182,000 | [6] | ||||
Long-term Risk Management Liabilities | 15,000 | [6] | 15,000 | [6] | 424,000 | [6] | ||||
Total Liabilities | 582,000 | [6] | 582,000 | [6] | 1,606,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -123,000 | [6] | -123,000 | [6] | -1,053,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 149,000 | [6] | 149,000 | [6] | 220,000 | [6] | ||||
Long-term Risk Management Assets | 149,000 | [6] | 149,000 | [6] | 148,000 | [6] | ||||
Total Assets | 298,000 | [6] | 298,000 | [6] | 368,000 | [6] | ||||
Current Risk Management Liabilities | 370,000 | [6] | 370,000 | [6] | 807,000 | [6] | ||||
Long-term Risk Management Liabilities | 7,000 | [6] | 7,000 | [6] | 292,000 | [6] | ||||
Total Liabilities | 377,000 | [6] | 377,000 | [6] | 1,099,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -79,000 | [6] | -79,000 | [6] | -731,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 315,000 | [6] | 315,000 | [6] | 464,000 | [6] | ||||
Long-term Risk Management Assets | 310,000 | [6] | 310,000 | [6] | 303,000 | [6] | ||||
Total Assets | 625,000 | [6] | 625,000 | [6] | 767,000 | [6] | ||||
Current Risk Management Liabilities | 774,000 | [6] | 774,000 | [6] | 1,658,000 | [6] | ||||
Long-term Risk Management Liabilities | 18,000 | [6] | 18,000 | [6] | 596,000 | [6] | ||||
Total Liabilities | 792,000 | [6] | 792,000 | [6] | 2,254,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -167,000 | [6] | -167,000 | [6] | -1,487,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 13,000 | [6] | 13,000 | [6] | 42,000 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 13,000 | [6] | 13,000 | [6] | 42,000 | [6] | ||||
Current Risk Management Liabilities | 12,000 | [6] | 12,000 | [6] | 17,000 | [6] | ||||
Long-term Risk Management Liabilities | 7,000 | [6] | 7,000 | [6] | 0 | [6] | ||||
Total Liabilities | 19,000 | [6] | 19,000 | [6] | 17,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -6,000 | [6] | -6,000 | [6] | 25,000 | [6] | ||||
Commodity [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 15,000 | [6] | 15,000 | [6] | 41,000 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 15,000 | [6] | 15,000 | [6] | 41,000 | [6] | ||||
Current Risk Management Liabilities | 14,000 | [6] | 14,000 | [6] | 17,000 | [6] | ||||
Long-term Risk Management Liabilities | 8,000 | [6] | 8,000 | [6] | 0 | [6] | ||||
Total Liabilities | 22,000 | [6] | 22,000 | [6] | 17,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -7,000 | [6] | -7,000 | [6] | 24,000 | [6] | ||||
Interest Rate and Foreign Currency [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 820,000,000 | 820,000,000 | 1,199,000,000 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 2,000,000 | [1] | 2,000,000 | [1] | 37,000,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -24,000,000 | -24,000,000 | -30,000,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -4,000,000 | -4,000,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 0 | [1] | 0 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | 2,836,000 | 2,836,000 | 2,077,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -930,000 | -1,013,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 200,000,000 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 0 | [1] | 0 | [1] | 19,524,000 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -16,386,000 | -16,386,000 | -19,647,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -1,640,000 | -1,600,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 0 | [1] | 0 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | 7,076,000 | 7,076,000 | 8,095,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,359,000 | 1,359,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 0 | [1] | 0 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | 5,891,000 | 5,891,000 | 6,460,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 759,000 | 759,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ||||||||||
Hedging Assets | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Hedging Liabilities | 0 | [1] | 0 | [1] | 0 | [1] | ||||
AOCI Gain (Loss) Net of Tax | -13,871,000 | -13,871,000 | -15,571,000 | |||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -2,267,000 | -2,267,000 | ||||||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 4,000,000 | [6] | 4,000,000 | [6] | 3,000,000 | [6] | ||||
Long-term Risk Management Assets | 1,000,000 | [6] | 1,000,000 | [6] | 1,000,000 | [6] | ||||
Total Assets | 5,000,000 | [6] | 5,000,000 | [6] | 4,000,000 | [6] | ||||
Current Risk Management Liabilities | 1,000,000 | [6] | 1,000,000 | [6] | 35,000,000 | [6] | ||||
Long-term Risk Management Liabilities | 13,000,000 | [6] | 13,000,000 | [6] | 6,000,000 | [6] | ||||
Total Liabilities | 14,000,000 | [6] | 14,000,000 | [6] | 41,000,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -9,000,000 | [6] | -9,000,000 | [6] | -37,000,000 | [6] | ||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Current Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Current Risk Management Liabilities | 0 | [6] | 0 | [6] | 19,524,000 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 0 | [6] | 0 | [6] | 19,524,000 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | 0 | [6] | -19,524,000 | [6] | ||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Current Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Current Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Assets | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Current Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Long-term Risk Management Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total Liabilities | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | 0 | [6] | 0 | [6] | ||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 464,000,000 | 464,000,000 | 624,000,000 | |||||||
Long-term Risk Management Assets | 440,000,000 | 440,000,000 | 534,000,000 | |||||||
Total Assets | 904,000,000 | 904,000,000 | 1,158,000,000 | |||||||
Current Risk Management Liabilities | 413,000,000 | 413,000,000 | 624,000,000 | |||||||
Long-term Risk Management Liabilities | 318,000,000 | 318,000,000 | 395,000,000 | |||||||
Total Liabilities | 731,000,000 | 731,000,000 | 1,019,000,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 173,000,000 | 173,000,000 | 139,000,000 | |||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 68,826,000 | 68,826,000 | 127,983,000 | |||||||
Long-term Risk Management Assets | 32,727,000 | 32,727,000 | 60,713,000 | |||||||
Total Assets | 101,553,000 | 101,553,000 | 188,696,000 | |||||||
Current Risk Management Liabilities | 60,360,000 | 60,360,000 | 120,612,000 | |||||||
Long-term Risk Management Liabilities | 25,018,000 | 25,018,000 | 47,705,000 | |||||||
Total Liabilities | 85,378,000 | 85,378,000 | 168,317,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 16,175,000 | 16,175,000 | 20,379,000 | |||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 45,137,000 | 45,137,000 | 93,488,000 | |||||||
Long-term Risk Management Assets | 21,581,000 | 21,581,000 | 41,701,000 | |||||||
Total Assets | 66,718,000 | 66,718,000 | 135,189,000 | |||||||
Current Risk Management Liabilities | 41,179,000 | 41,179,000 | 102,764,000 | |||||||
Long-term Risk Management Liabilities | 16,843,000 | 16,843,000 | 34,006,000 | |||||||
Total Liabilities | 58,022,000 | 58,022,000 | 136,770,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 8,696,000 | 8,696,000 | -1,581,000 | |||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 96,943,000 | 96,943,000 | 183,528,000 | |||||||
Long-term Risk Management Assets | 44,907,000 | 44,907,000 | 85,326,000 | |||||||
Total Assets | 141,850,000 | 141,850,000 | 268,854,000 | |||||||
Current Risk Management Liabilities | 85,293,000 | 85,293,000 | 173,055,000 | |||||||
Long-term Risk Management Liabilities | 34,327,000 | 34,327,000 | 67,044,000 | |||||||
Total Liabilities | 119,620,000 | 119,620,000 | 240,099,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 22,230,000 | 22,230,000 | 28,755,000 | |||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 1,407,000 | 1,407,000 | 1,699,000 | |||||||
Long-term Risk Management Assets | 149,000 | 149,000 | 0 | |||||||
Total Assets | 1,556,000 | 1,556,000 | 1,699,000 | |||||||
Current Risk Management Liabilities | 1,943,000 | 1,943,000 | 7,038,000 | |||||||
Long-term Risk Management Liabilities | 7,000 | 7,000 | 0 | |||||||
Total Liabilities | 1,950,000 | 1,950,000 | 7,038,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | -394,000 | -394,000 | -5,339,000 | |||||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 1,459,000 | 1,459,000 | 2,845,000 | |||||||
Long-term Risk Management Assets | 21,000 | 21,000 | 0 | |||||||
Total Assets | 1,480,000 | 1,480,000 | 2,845,000 | |||||||
Current Risk Management Liabilities | 1,353,000 | 1,353,000 | 3,278,000 | |||||||
Long-term Risk Management Liabilities | 8,000 | 8,000 | 0 | |||||||
Total Liabilities | 1,361,000 | 1,361,000 | 3,278,000 | |||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 119,000 | 119,000 | -433,000 | |||||||
Gross Amounts Offset in the Statement of Financial Position [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -293,000,000 | [7] | -293,000,000 | [7] | -433,000,000 | [7] | ||||
Long-term Risk Management Assets | -126,000,000 | [7] | -126,000,000 | [7] | -166,000,000 | [7] | ||||
Total Assets | -419,000,000 | [7] | -419,000,000 | [7] | -599,000,000 | [7] | ||||
Current Risk Management Liabilities | -311,000,000 | [7] | -311,000,000 | [7] | -469,000,000 | [7] | ||||
Long-term Risk Management Liabilities | -136,000,000 | [7] | -136,000,000 | [7] | -181,000,000 | [7] | ||||
Total Liabilities | -447,000,000 | [7] | -447,000,000 | [7] | -650,000,000 | [7] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 28,000,000 | [7] | 28,000,000 | [7] | 51,000,000 | [7] | ||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -44,276,000 | [8] | -44,276,000 | [8] | -97,023,000 | [8] | ||||
Long-term Risk Management Assets | -11,888,000 | [8] | -11,888,000 | [8] | -26,353,000 | [8] | ||||
Total Assets | -56,164,000 | [8] | -56,164,000 | [8] | -123,376,000 | [8] | ||||
Current Risk Management Liabilities | -48,719,000 | [8] | -48,719,000 | [8] | -103,914,000 | [8] | ||||
Long-term Risk Management Liabilities | -12,937,000 | [8] | -12,937,000 | [8] | -29,229,000 | [8] | ||||
Total Liabilities | -61,656,000 | [8] | -61,656,000 | [8] | -133,143,000 | [8] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 5,492,000 | [8] | 5,492,000 | [8] | 9,767,000 | [8] | ||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -28,987,000 | [8] | -28,987,000 | [8] | -66,514,000 | [8] | ||||
Long-term Risk Management Assets | -7,848,000 | [8] | -7,848,000 | [8] | -18,132,000 | [8] | ||||
Total Assets | -36,835,000 | [8] | -36,835,000 | [8] | -84,646,000 | [8] | ||||
Current Risk Management Liabilities | -31,911,000 | [8] | -31,911,000 | [8] | -71,247,000 | [8] | ||||
Long-term Risk Management Liabilities | -8,536,000 | [8] | -8,536,000 | [8] | -20,108,000 | [8] | ||||
Total Liabilities | -40,447,000 | [8] | -40,447,000 | [8] | -91,355,000 | [8] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 3,612,000 | [8] | 3,612,000 | [8] | 6,709,000 | [8] | ||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -62,765,000 | [8] | -62,765,000 | [8] | -139,215,000 | [8] | ||||
Long-term Risk Management Assets | -16,313,000 | [8] | -16,313,000 | [8] | -37,038,000 | [8] | ||||
Total Assets | -79,078,000 | [8] | -79,078,000 | [8] | -176,253,000 | [8] | ||||
Current Risk Management Liabilities | -68,862,000 | [8] | -68,862,000 | [8] | -148,900,000 | [8] | ||||
Long-term Risk Management Liabilities | -17,750,000 | [8] | -17,750,000 | [8] | -41,079,000 | [8] | ||||
Total Liabilities | -86,612,000 | [8] | -86,612,000 | [8] | -189,979,000 | [8] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 7,534,000 | [8] | 7,534,000 | [8] | 13,726,000 | [8] | ||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -555,000 | [8] | -555,000 | [8] | -1,190,000 | [8] | ||||
Long-term Risk Management Assets | 0 | [8] | 0 | [8] | 31,000 | [8] | ||||
Total Assets | -555,000 | [8] | -555,000 | [8] | -1,159,000 | [8] | ||||
Current Risk Management Liabilities | -555,000 | [8] | -555,000 | [8] | -1,190,000 | [8] | ||||
Long-term Risk Management Liabilities | -7,000 | [8] | -7,000 | [8] | 31,000 | [8] | ||||
Total Liabilities | -562,000 | [8] | -562,000 | [8] | -1,159,000 | [8] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 7,000 | [8] | 7,000 | [8] | 0 | [8] | ||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | -1,057,000 | [8] | -1,057,000 | [8] | -2,150,000 | [8] | ||||
Long-term Risk Management Assets | 0 | [8] | 0 | [8] | 0 | [8] | ||||
Total Assets | -1,057,000 | [8] | -1,057,000 | [8] | -2,150,000 | [8] | ||||
Current Risk Management Liabilities | -1,057,000 | [8] | -1,057,000 | [8] | -2,150,000 | [8] | ||||
Long-term Risk Management Liabilities | -8,000 | [8] | -8,000 | [8] | 0 | [8] | ||||
Total Liabilities | -1,065,000 | [8] | -1,065,000 | [8] | -2,150,000 | [8] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 8,000 | [8] | 8,000 | [8] | 0 | [8] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 171,000,000 | [9] | 171,000,000 | [9] | 191,000,000 | [9] | ||||
Long-term Risk Management Assets | 314,000,000 | [9] | 314,000,000 | [9] | 368,000,000 | [9] | ||||
Total Assets | 485,000,000 | [9] | 485,000,000 | [9] | 559,000,000 | [9] | ||||
Current Risk Management Liabilities | 102,000,000 | [9] | 102,000,000 | [9] | 155,000,000 | [9] | ||||
Long-term Risk Management Liabilities | 182,000,000 | [9] | 182,000,000 | [9] | 214,000,000 | [9] | ||||
Total Liabilities | 284,000,000 | [9] | 284,000,000 | [9] | 369,000,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 201,000,000 | [9] | 201,000,000 | [9] | 190,000,000 | [9] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 24,550,000 | [9] | 24,550,000 | [9] | 30,960,000 | [9] | ||||
Long-term Risk Management Assets | 20,839,000 | [9] | 20,839,000 | [9] | 34,360,000 | [9] | ||||
Total Assets | 45,389,000 | [9] | 45,389,000 | [9] | 65,320,000 | [9] | ||||
Current Risk Management Liabilities | 11,641,000 | [9] | 11,641,000 | [9] | 16,698,000 | [9] | ||||
Long-term Risk Management Liabilities | 12,081,000 | [9] | 12,081,000 | [9] | 18,476,000 | [9] | ||||
Total Liabilities | 23,722,000 | [9] | 23,722,000 | [9] | 35,174,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 21,667,000 | [9] | 21,667,000 | [9] | 30,146,000 | [9] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 16,150,000 | [9] | 16,150,000 | [9] | 26,974,000 | [9] | ||||
Long-term Risk Management Assets | 13,733,000 | [9] | 13,733,000 | [9] | 23,569,000 | [9] | ||||
Total Assets | 29,883,000 | [9] | 29,883,000 | [9] | 50,543,000 | [9] | ||||
Current Risk Management Liabilities | 9,268,000 | [9] | 9,268,000 | [9] | 31,517,000 | [9] | ||||
Long-term Risk Management Liabilities | 8,307,000 | [9] | 8,307,000 | [9] | 13,898,000 | [9] | ||||
Total Liabilities | 17,575,000 | [9] | 17,575,000 | [9] | 45,415,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 12,308,000 | [9] | 12,308,000 | [9] | 5,128,000 | [9] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Ohio Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 34,178,000 | [9] | 34,178,000 | [9] | 44,313,000 | [9] | ||||
Long-term Risk Management Assets | 28,594,000 | [9] | 28,594,000 | [9] | 48,288,000 | [9] | ||||
Total Assets | 62,772,000 | [9] | 62,772,000 | [9] | 92,601,000 | [9] | ||||
Current Risk Management Liabilities | 16,431,000 | [9] | 16,431,000 | [9] | 24,155,000 | [9] | ||||
Long-term Risk Management Liabilities | 16,577,000 | [9] | 16,577,000 | [9] | 25,965,000 | [9] | ||||
Total Liabilities | 33,008,000 | [9] | 33,008,000 | [9] | 50,120,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 29,764,000 | [9] | 29,764,000 | [9] | 42,481,000 | [9] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 852,000 | [9] | 852,000 | [9] | 509,000 | [9] | ||||
Long-term Risk Management Assets | 149,000 | [9] | 149,000 | [9] | 31,000 | [9] | ||||
Total Assets | 1,001,000 | [9] | 1,001,000 | [9] | 540,000 | [9] | ||||
Current Risk Management Liabilities | 1,388,000 | [9] | 1,388,000 | [9] | 5,848,000 | [9] | ||||
Long-term Risk Management Liabilities | 0 | [9] | 0 | [9] | 31,000 | [9] | ||||
Total Liabilities | 1,388,000 | [9] | 1,388,000 | [9] | 5,879,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | -387,000 | [9] | -387,000 | [9] | -5,339,000 | [9] | ||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Fair Value of Derivative Instruments | ||||||||||
Current Risk Management Assets | 402,000 | [9] | 402,000 | [9] | 695,000 | [9] | ||||
Long-term Risk Management Assets | 21,000 | [9] | 21,000 | [9] | 0 | [9] | ||||
Total Assets | 423,000 | [9] | 423,000 | [9] | 695,000 | [9] | ||||
Current Risk Management Liabilities | 296,000 | [9] | 296,000 | [9] | 1,128,000 | [9] | ||||
Long-term Risk Management Liabilities | 0 | [9] | 0 | [9] | 0 | [9] | ||||
Total Liabilities | 296,000 | [9] | 296,000 | [9] | 1,128,000 | [9] | ||||
Total MTM Derivative Contract Net Assets (Liabilities) | 127,000 | [9] | 127,000 | [9] | -433,000 | [9] | ||||
Power [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 464,000,000 | 464,000,000 | 498,000,000 | |||||||
Power [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 75,861,000 | 75,861,000 | 94,059,000 | |||||||
Power [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 49,918,000 | 49,918,000 | 64,791,000 | |||||||
Power [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 104,093,000 | 104,093,000 | 132,188,000 | |||||||
Power [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 8,000 | 8,000 | 0 | |||||||
Power [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 10,000 | 10,000 | 0 | |||||||
Coal [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 6,000,000 | 6,000,000 | 10,000,000 | |||||||
Coal [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 282,000 | 282,000 | 1,401,000 | |||||||
Coal [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 3,980,000 | 3,980,000 | 2,711,000 | |||||||
Coal [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 813,000 | 813,000 | 3,033,000 | |||||||
Coal [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 2,075,000 | 2,075,000 | 1,980,000 | |||||||
Coal [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Mass Notional Amount | 1,229,000 | 1,229,000 | 1,312,000 | |||||||
Natural Gas [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 141,000,000 | 141,000,000 | 147,000,000 | |||||||
Natural Gas [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 4,121,000 | 4,121,000 | 10,077,000 | |||||||
Natural Gas [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 2,711,000 | 2,711,000 | 6,922,000 | |||||||
Natural Gas [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 5,654,000 | 5,654,000 | 14,163,000 | |||||||
Natural Gas [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 0 | 0 | 0 | |||||||
Natural Gas [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Energy Notional Amount | 0 | 0 | 0 | |||||||
Heating Oil and Gasoline [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 5,000,000 | 5,000,000 | 6,000,000 | |||||||
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 981,000 | 981,000 | 1,050,000 | |||||||
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 484,000 | 484,000 | 532,000 | |||||||
Heating Oil and Gasoline [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 1,155,000 | 1,155,000 | 1,260,000 | |||||||
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 491,000 | 491,000 | 616,000 | |||||||
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Volume Notional Amount | 603,000 | 603,000 | 585,000 | |||||||
Interest Rate Contract [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 201,000,000 | 201,000,000 | 235,000,000 | |||||||
Interest Rate Contract [Member] | Appalachian Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 16,501,000 | 16,501,000 | 24,146,000 | |||||||
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 10,858,000 | 10,858,000 | 16,584,000 | |||||||
Interest Rate Contract [Member] | Ohio Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 22,642,000 | 22,642,000 | 33,934,000 | |||||||
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Commodity: | ||||||||||
Derivative, Notional Amount | 0 | 0 | 0 | |||||||
Utility Operations Revenues [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 4,000,000 | 5,000,000 | 17,000,000 | 19,000,000 | ||||||
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 746,000 | 378,000 | 1,619,000 | -548,000 | ||||||
Electric Generation, Transmission and Distribution Revenues [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,742,000 | 3,814,000 | 9,586,000 | 9,206,000 | ||||||
Electric Generation, Transmission and Distribution Revenues [Member] | Ohio Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 66,000 | 87,000 | 3,599,000 | 11,118,000 | ||||||
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 25,000 | 71,000 | 241,000 | 231,000 | ||||||
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 51,000 | 174,000 | 381,000 | 426,000 | ||||||
Sales to AEP Affiliates [Member] | Appalachian Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Sales to AEP Affiliates [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Sales to AEP Affiliates [Member] | Ohio Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Sales to AEP Affiliates [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Other Revenues [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 9,000,000 | 20,000,000 | 39,000,000 | 28,000,000 | ||||||
Fuel and Other Consumables Used for Electric Generation [Member] | Appalachian Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Fuel and Other Consumables Used for Electric Generation [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Fuel and Other Consumables Used for Electric Generation [Member] | Ohio Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Fuel and Other Consumables Used for Electric Generation [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Fuel and Other Consumables Used for Electric Generation [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | ||||||
Regulatory Assets [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | [10] | 2,000,000 | [10] | -3,000,000 | [10] | -35,000,000 | [10] | ||
Regulatory Assets [Member] | Appalachian Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | [10] | -138,000 | [10] | 0 | [10] | -6,133,000 | [10] | ||
Regulatory Assets [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -1,349,000 | [10] | -1,213,000 | [10] | -1,648,000 | [10] | -7,228,000 | [10] | ||
Regulatory Assets [Member] | Ohio Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | [10] | 3,000,000 | [10] | -5,158,000 | [10] | -9,026,000 | [10] | ||
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 960,000 | [10] | 598,000 | [10] | 3,162,000 | [10] | -5,360,000 | [10] | ||
Regulatory Assets [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 421,000 | [10] | 115,000 | [10] | 427,000 | [10] | -6,977,000 | [10] | ||
Regulatory Liabilities [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -5,000,000 | [10] | -14,000,000 | [10] | -10,000,000 | [10] | 12,000,000 | [10] | ||
Regulatory Liabilities [Member] | Appalachian Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -950,000 | [10] | -1,672,000 | [10] | -1,160,000 | [10] | 8,166,000 | [10] | ||
Regulatory Liabilities [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -2,347,000 | [10] | -5,267,000 | [10] | -9,209,000 | [10] | 1,851,000 | [10] | ||
Regulatory Liabilities [Member] | Ohio Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | -1,264,000 | [10] | -6,788,000 | [10] | 1,557,000 | [10] | 390,000 | [10] | ||
Regulatory Liabilities [Member] | Public Service Co Of Oklahoma [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 18,000 | [10] | 2,000 | [10] | 18,000 | [10] | 3,000 | [10] | ||
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member] | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ||||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | $130,000 | [10] | $11,000 | [10] | $157,000 | [10] | $6,000 | [10] | ||
[1] | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets. | |||||||||
[2] | 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.'' | |||||||||
[3] | The September 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $1 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $4 million in 2013, $48 million in periods 2014-2016, $8 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $6 million in 2013, $60 million in periods 2014-2016, $32 million in periods 2017-2018 and $25 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||
[4] | The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||
[5] | Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||
[6] | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||
[7] | Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." Amounts also include de-designated risk management contracts. | |||||||||
[8] | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging." | |||||||||
[9] | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | |||||||||
[10] | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. |
Fair_Value_Longterm_Debt_Other
Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | $17,568,000,000 | $17,568,000,000 | $17,757,000,000 | |||||
Long Term Debt, Fair Value | 19,316,000,000 | 19,316,000,000 | 20,907,000,000 | |||||
Other Temporary Investments | ||||||||
Cost | 280,000,000 | 280,000,000 | 316,000,000 | |||||
Gross Unrealized Gains | 8,000,000 | 8,000,000 | 8,000,000 | |||||
Gross Unrealized Losses | 0 | 0 | 0 | |||||
Estimated Fair Value | 288,000,000 | 288,000,000 | 324,000,000 | |||||
Debt and Equity Securities Within Other Temporary Investments [Abstract] | ||||||||
Proceeds from Investment Sales | 0 | 0 | 0 | 0 | ||||
Purchases of Investments | 6,000,000 | 0 | 17,000,000 | 1,000,000 | ||||
Gross Realized Gains on Investment Sales | 0 | 0 | 0 | 0 | ||||
Gross Realized Losses on Investment Sales | 0 | 0 | 0 | 0 | ||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 1,839,000,000 | 1,839,000,000 | 1,706,000,000 | |||||
Gross Unrealized Gains | 452,000,000 | 452,000,000 | 349,000,000 | |||||
Other-Than-Temporary Impairments | 86,000,000 | 86,000,000 | 80,000,000 | |||||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ||||||||
Proceeds from Investment Sales | 250,000,000 | 182,000,000 | 635,000,000 | 699,000,000 | ||||
Purchases of Investments | 264,000,000 | 199,000,000 | 676,000,000 | 744,000,000 | ||||
Gross Realized Gains on Investment Sales | 4,000,000 | 2,000,000 | 16,000,000 | 7,000,000 | ||||
Gross Realized Losses on Investment Sales | 2,000,000 | 1,000,000 | 12,000,000 | 3,000,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 1,839,000,000 | 1,839,000,000 | 1,706,000,000 | |||||
Fair Value Measurements (Textuals) [Abstract] | ||||||||
Adjusted Cost of Debt Securities | 866,000,000 | 866,000,000 | 889,000,000 | |||||
Adjusted Cost of Domestic Equity Securities | 506,000,000 | 506,000,000 | 451,000,000 | |||||
Appalachian Power Co [Member] | ||||||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | 3,427,917,000 | 3,427,917,000 | 3,702,442,000 | |||||
Long Term Debt, Fair Value | 3,957,321,000 | 3,957,321,000 | 4,555,143,000 | |||||
Indiana Michigan Power Co [Member] | ||||||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | 2,271,613,000 | 2,271,613,000 | 2,057,666,000 | |||||
Long Term Debt, Fair Value | 2,461,671,000 | 2,461,671,000 | 2,372,017,000 | |||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 1,839,118,000 | 1,839,118,000 | 1,705,772,000 | |||||
Gross Unrealized Gains | 452,843,000 | 452,843,000 | 348,776,000 | |||||
Other-Than-Temporary Impairments | 85,931,000 | 85,931,000 | 79,519,000 | |||||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ||||||||
Proceeds from Investment Sales | 249,314,000 | 181,988,000 | 635,256,000 | 698,567,000 | ||||
Purchases of Investments | 263,958,000 | 199,150,000 | 675,727,000 | 744,131,000 | ||||
Gross Realized Gains on Investment Sales | 4,113,000 | 2,046,000 | 16,011,000 | 6,978,000 | ||||
Gross Realized Losses on Investment Sales | 2,147,000 | 924,000 | 11,859,000 | 3,143,000 | ||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 1,839,118,000 | 1,839,118,000 | 1,705,772,000 | |||||
Fair Value Measurements (Textuals) [Abstract] | ||||||||
Adjusted Cost of Debt Securities | 866,000,000 | 866,000,000 | 889,000,000 | |||||
Adjusted Cost of Domestic Equity Securities | 506,000,000 | 506,000,000 | 451,000,000 | |||||
Ohio Power Co [Member] | ||||||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | 3,698,574,000 | 3,698,574,000 | 3,860,440,000 | |||||
Long Term Debt, Fair Value | 4,071,613,000 | 4,071,613,000 | 4,560,337,000 | |||||
Public Service Co Of Oklahoma [Member] | ||||||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | 949,826,000 | 949,826,000 | 949,871,000 | |||||
Long Term Debt, Fair Value | 1,090,934,000 | 1,090,934,000 | 1,175,759,000 | |||||
Southwestern Electric Power Co [Member] | ||||||||
Book Values and Fair Values of Long - term Debt | ||||||||
Total Long-term Debt Outstanding | 2,043,244,000 | 2,043,244,000 | 2,046,228,000 | |||||
Long Term Debt, Fair Value | 2,254,078,000 | 2,254,078,000 | 2,400,509,000 | |||||
Cash [Member] | ||||||||
Other Temporary Investments | ||||||||
Cost | 188,000,000 | 188,000,000 | 241,000,000 | |||||
Gross Unrealized Gains | 0 | 0 | 0 | |||||
Gross Unrealized Losses | 0 | 0 | 0 | |||||
Estimated Fair Value | 188,000,000 | [1] | 188,000,000 | [1] | 241,000,000 | [1] | ||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 15,000,000 | [2] | 15,000,000 | [2] | 17,000,000 | [2] | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 15,000,000 | [2] | 15,000,000 | [2] | 17,000,000 | [2] | ||
Cash [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 14,438,000 | [3] | 14,438,000 | [3] | 16,783,000 | [3] | ||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 14,438,000 | [3] | 14,438,000 | [3] | 16,783,000 | [3] | ||
Fixed Income Funds [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 903,000,000 | 903,000,000 | 953,000,000 | |||||
Gross Unrealized Gains | 37,000,000 | 37,000,000 | 64,000,000 | |||||
Other-Than-Temporary Impairments | 5,000,000 | 5,000,000 | 3,000,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 903,000,000 | 903,000,000 | 953,000,000 | |||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 903,388,000 | 903,388,000 | 953,407,000 | |||||
Gross Unrealized Gains | 37,912,000 | 37,912,000 | 64,177,000 | |||||
Other-Than-Temporary Impairments | 4,806,000 | 4,806,000 | 2,962,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 903,388,000 | 903,388,000 | 953,407,000 | |||||
Mutual Funds Fixed Income [Member] | ||||||||
Other Temporary Investments | ||||||||
Cost | 79,000,000 | 79,000,000 | 65,000,000 | |||||
Gross Unrealized Gains | 0 | 0 | 2,000,000 | |||||
Gross Unrealized Losses | 0 | 0 | 0 | |||||
Estimated Fair Value | 79,000,000 | 79,000,000 | 67,000,000 | |||||
Domestic [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 921,000,000 | [4] | 921,000,000 | [4] | 736,000,000 | [4] | ||
Gross Unrealized Gains | 415,000,000 | 415,000,000 | 285,000,000 | |||||
Other-Than-Temporary Impairments | 81,000,000 | 81,000,000 | 77,000,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 921,000,000 | [4] | 921,000,000 | [4] | 736,000,000 | [4] | ||
Domestic [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 921,292,000 | [4] | 921,292,000 | [4] | 735,582,000 | [4] | ||
Gross Unrealized Gains | 414,931,000 | 414,931,000 | 284,599,000 | |||||
Other-Than-Temporary Impairments | 81,125,000 | 81,125,000 | 76,557,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 921,292,000 | [4] | 921,292,000 | [4] | 735,582,000 | [4] | ||
Mutual Funds Equity [Member] | ||||||||
Other Temporary Investments | ||||||||
Cost | 13,000,000 | 13,000,000 | 10,000,000 | |||||
Gross Unrealized Gains | 8,000,000 | 8,000,000 | 6,000,000 | |||||
Gross Unrealized Losses | 0 | 0 | 0 | |||||
Estimated Fair Value | 21,000,000 | [4] | 21,000,000 | [4] | 16,000,000 | [4] | ||
Cash and Cash Equivalents [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 15,000,000 | 15,000,000 | 17,000,000 | |||||
Gross Unrealized Gains | 0 | 0 | 0 | |||||
Other-Than-Temporary Impairments | 0 | 0 | 0 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 15,000,000 | 15,000,000 | 17,000,000 | |||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 14,438,000 | 14,438,000 | 16,783,000 | |||||
Gross Unrealized Gains | 0 | 0 | 0 | |||||
Other-Than-Temporary Impairments | 0 | 0 | 0 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 14,438,000 | 14,438,000 | 16,783,000 | |||||
US Government Agencies Debt Securities [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 621,000,000 | 621,000,000 | 648,000,000 | |||||
Gross Unrealized Gains | 34,000,000 | 34,000,000 | 58,000,000 | |||||
Other-Than-Temporary Impairments | 3,000,000 | 3,000,000 | 1,000,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 621,000,000 | 621,000,000 | 648,000,000 | |||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 620,944,000 | 620,944,000 | 647,918,000 | |||||
Gross Unrealized Gains | 34,377,000 | 34,377,000 | 58,268,000 | |||||
Other-Than-Temporary Impairments | 2,662,000 | 2,662,000 | 747,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 620,944,000 | 620,944,000 | 647,918,000 | |||||
Corporate Debt [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 38,000,000 | 38,000,000 | 35,000,000 | |||||
Gross Unrealized Gains | 2,000,000 | 2,000,000 | 5,000,000 | |||||
Other-Than-Temporary Impairments | 2,000,000 | 2,000,000 | 1,000,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 38,000,000 | 38,000,000 | 35,000,000 | |||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 38,272,000 | 38,272,000 | 35,399,000 | |||||
Gross Unrealized Gains | 2,684,000 | 2,684,000 | 4,903,000 | |||||
Other-Than-Temporary Impairments | 1,786,000 | 1,786,000 | 1,352,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 38,272,000 | 38,272,000 | 35,399,000 | |||||
State and Local Jurisdiction [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 244,000,000 | 244,000,000 | 270,000,000 | |||||
Gross Unrealized Gains | 1,000,000 | 1,000,000 | 1,000,000 | |||||
Other-Than-Temporary Impairments | 0 | 0 | 1,000,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 244,000,000 | 244,000,000 | 270,000,000 | |||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 244,172,000 | 244,172,000 | 270,090,000 | |||||
Gross Unrealized Gains | 851,000 | 851,000 | 1,006,000 | |||||
Other-Than-Temporary Impairments | 358,000 | 358,000 | 863,000 | |||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 244,172,000 | 244,172,000 | 270,090,000 | |||||
Within One Year [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 74,000,000 | 74,000,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 74,000,000 | 74,000,000 | ||||||
Within One Year [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 73,908,000 | 73,908,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 73,908,000 | 73,908,000 | ||||||
One Year To Five Year [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 378,000,000 | 378,000,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 378,000,000 | 378,000,000 | ||||||
One Year To Five Year [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 378,271,000 | 378,271,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 378,271,000 | 378,271,000 | ||||||
Five Year To Ten Year [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 210,000,000 | 210,000,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 210,000,000 | 210,000,000 | ||||||
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 210,201,000 | 210,201,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 210,201,000 | 210,201,000 | ||||||
After Ten Year [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 241,000,000 | 241,000,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | 241,000,000 | 241,000,000 | ||||||
After Ten Year [Member] | Indiana Michigan Power Co [Member] | ||||||||
Nuclear Trust Fund Investments [Abstract] | ||||||||
Estimated Fair Value | 241,008,000 | 241,008,000 | ||||||
Contractual Maturities, Fair Value of Debt Securities | ||||||||
Contractual Maturities, Fair Value of Debt Securities | $241,008,000 | $241,008,000 | ||||||
[1] | Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||
[2] | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||
[3] | Amounts in bOtherb column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||
[4] | Amounts represent publicly traded equity securities and equity-based mutual funds. |
Fair_Value_Assets_and_Liabilit
Fair Value Assets and Liabilities (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||||
Assets: | ||||||||||
Cash and Cash Equivalents | $147,000,000 | [1] | $147,000,000 | [1] | $279,000,000 | [1] | ||||
Other Temporary Investments | 288,000,000 | 288,000,000 | 324,000,000 | |||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 485,000,000 | 485,000,000 | 559,000,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,839,000,000 | 1,839,000,000 | 1,706,000,000 | |||||||
Total Assets | 2,759,000,000 | 2,759,000,000 | 2,868,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 284,000,000 | 284,000,000 | 369,000,000 | |||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | ||||||||||
Beginning Balance | 122,000,000 | 97,000,000 | 86,000,000 | 69,000,000 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | -2,000,000 | [2],[3] | -5,000,000 | [2],[3] | -9,000,000 | [2],[3] | -16,000,000 | [2],[3] | ||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | 13,000,000 | [2] | 7,000,000 | [2] | 32,000,000 | [2] | 20,000,000 | [2] | ||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | -3,000,000 | 5,000,000 | -3,000,000 | 2,000,000 | ||||||
Purchases, Issuances and Settlements | -8,000,000 | [4] | 4,000,000 | [4] | -7,000,000 | [4] | 33,000,000 | [4] | ||
Transfers into Level 3 | 0 | [5],[6] | -3,000,000 | [5],[6] | 18,000,000 | [5],[6] | 10,000,000 | [5],[6] | ||
Transfers out of Level 3 | -2,000,000 | [6],[7] | -1,000,000 | [6],[7] | -1,000,000 | [6],[7] | -21,000,000 | [6],[7] | ||
Changes in Fair Value Allocated to Regulated Jurisdictions | 0 | [8] | 0 | [8] | 4,000,000 | [8] | 7,000,000 | [8] | ||
Ending Balance | 120,000,000 | 104,000,000 | 120,000,000 | 104,000,000 | ||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Counterparty Credit Risk | 374 | [9] | ||||||||
Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 14,000,000 | [1] | 14,000,000 | [1] | 6,000,000 | [1] | ||||
Other Temporary Investments | 273,000,000 | 273,000,000 | 310,000,000 | |||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 36,000,000 | 36,000,000 | 55,000,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 927,000,000 | 927,000,000 | 743,000,000 | |||||||
Total Assets | 1,250,000,000 | 1,250,000,000 | 1,114,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 40,000,000 | 40,000,000 | 45,000,000 | |||||||
Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 1,000,000 | [1] | 1,000,000 | [1] | 1,000,000 | [1] | ||||
Other Temporary Investments | 7,000,000 | 7,000,000 | 5,000,000 | |||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 704,000,000 | 704,000,000 | 968,000,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,000,000 | 903,000,000 | 953,000,000 | |||||||
Total Assets | 1,615,000,000 | 1,615,000,000 | 1,927,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 647,000,000 | 647,000,000 | 925,000,000 | |||||||
Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Other Temporary Investments | 0 | 0 | 0 | |||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 147,000,000 | 147,000,000 | 131,000,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Total Assets | 147,000,000 | 147,000,000 | 131,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 27,000,000 | 27,000,000 | 45,000,000 | |||||||
Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 132,000,000 | [1] | 132,000,000 | [1] | 272,000,000 | [1] | ||||
Other Temporary Investments | 8,000,000 | 8,000,000 | 9,000,000 | |||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -402,000,000 | -402,000,000 | -595,000,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 9,000,000 | 9,000,000 | 10,000,000 | |||||||
Total Assets | -253,000,000 | -253,000,000 | -304,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -430,000,000 | -430,000,000 | -646,000,000 | |||||||
2013 [Member] | Level 1 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 1,000,000 | 1,000,000 | 9,000,000 | |||||||
2013 [Member] | Level 2 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 4,000,000 | 4,000,000 | 16,000,000 | |||||||
2013 [Member] | Level 3 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 6,000,000 | 6,000,000 | 18,000,000 | |||||||
2014 - 2016 [Member] | Level 1 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | -3,000,000 | -3,000,000 | -3,000,000 | |||||||
2014 - 2016 [Member] | Level 2 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 48,000,000 | 48,000,000 | 61,000,000 | |||||||
2014 - 2016 [Member] | Level 3 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 60,000,000 | 60,000,000 | 31,000,000 | |||||||
2017 - 2018 [Member] | Level 1 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | -4,000,000 | -4,000,000 | -4,000,000 | |||||||
2017 - 2018 [Member] | Level 2 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 8,000,000 | 8,000,000 | 16,000,000 | |||||||
2017 - 2018 [Member] | Level 3 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 32,000,000 | 32,000,000 | 13,000,000 | |||||||
2019 - 2030 [Member] | Level 2 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 7,000,000 | 7,000,000 | 7,000,000 | |||||||
2019 - 2030 [Member] | Level 3 [Member] | ||||||||||
Fair Value Measurements 1 (Textuals) [Abstract] | ||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 25,000,000 | 25,000,000 | 24,000,000 | |||||||
Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 462,000,000 | [10],[11] | 462,000,000 | [10],[11] | 517,000,000 | [10],[12] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 259,000,000 | [10],[11] | 259,000,000 | [10],[11] | 292,000,000 | [10],[12] | ||||
Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 34,000,000 | [10],[11] | 34,000,000 | [10],[11] | 47,000,000 | [10],[12] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 40,000,000 | [10],[11] | 40,000,000 | [10],[11] | 45,000,000 | [10],[12] | ||||
Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 680,000,000 | [10],[11] | 680,000,000 | [10],[11] | 938,000,000 | [10],[12] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 613,000,000 | [10],[11] | 613,000,000 | [10],[11] | 838,000,000 | [10],[12] | ||||
Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 147,000,000 | [10],[11] | 147,000,000 | [10],[11] | 131,000,000 | [10],[12] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 24,000,000 | [10],[11] | 24,000,000 | [10],[11] | 45,000,000 | [10],[12] | ||||
Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -399,000,000 | [10],[11] | -399,000,000 | [10],[11] | -599,000,000 | [10],[12] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -418,000,000 | [10],[11] | -418,000,000 | [10],[11] | -636,000,000 | [10],[12] | ||||
Energy Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 139,000,000 | 139,000,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 23,000,000 | 23,000,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | 10.86 | [13] | 10.86 | [13] | ||||||
Forward Price Range High | 126.65 | [13] | 126.65 | [13] | ||||||
FTRs [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 8,000,000 | 8,000,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 4,000,000 | 4,000,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | -11.44 | [13] | -11.44 | [13] | ||||||
Forward Price Range High | 13.11 | [13] | 13.11 | [13] | ||||||
Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 9,000,000 | [10] | 9,000,000 | [10] | 24,000,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 11,000,000 | [10] | 11,000,000 | [10] | 36,000,000 | [10] | ||||
Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 2,000,000 | [10] | 2,000,000 | [10] | 8,000,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 22,000,000 | [10] | 22,000,000 | [10] | 28,000,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 23,000,000 | [10] | 23,000,000 | [10] | 48,000,000 | [10] | ||||
Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 3,000,000 | [10] | 3,000,000 | [10] | 0 | [10] | ||||
Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -15,000,000 | [10] | -15,000,000 | [10] | -12,000,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -15,000,000 | [10] | -15,000,000 | [10] | -12,000,000 | [10] | ||||
Interest Rate Foreign Currency Hedges [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 2,000,000 | 2,000,000 | 37,000,000 | |||||||
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 2,000,000 | 2,000,000 | 37,000,000 | |||||||
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Interest Rate Foreign Currency Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Fair Value Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 5,000,000 | 5,000,000 | 4,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 12,000,000 | 12,000,000 | 4,000,000 | |||||||
Fair Value Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Fair Value Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 2,000,000 | 2,000,000 | 2,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 9,000,000 | 9,000,000 | 2,000,000 | |||||||
Fair Value Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Fair Value Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 3,000,000 | 3,000,000 | 2,000,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 3,000,000 | 3,000,000 | 2,000,000 | |||||||
Appalachian Power Co [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 45,389,000 | 45,389,000 | 65,320,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 23,722,000 | 23,722,000 | 35,174,000 | |||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | ||||||||||
Beginning Balance | 12,976,000 | 12,864,000 | 10,979,000 | 1,971,000 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | -1,200,000 | [2],[3] | -3,540,000 | [2],[3] | -3,450,000 | [2],[3] | -5,108,000 | [2],[3] | ||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | 0 | [2] | 0 | [2] | 0 | [2] | 0 | [2] | ||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 403,000 | 0 | 312,000 | ||||||
Purchases, Issuances and Settlements | -1,058,000 | [4] | 929,000 | [4] | 1,712,000 | [4] | 10,605,000 | [4] | ||
Transfers into Level 3 | 13,000 | [5],[6] | 654,000 | [5],[6] | 961,000 | [5],[6] | 4,142,000 | [5],[6] | ||
Transfers out of Level 3 | -15,000 | [6],[7] | -287,000 | [6],[7] | -925,000 | [6],[7] | -4,910,000 | [6],[7] | ||
Changes in Fair Value Allocated to Regulated Jurisdictions | 195,000 | [8] | 17,000 | [8] | 1,634,000 | [8] | 4,028,000 | [8] | ||
Ending Balance | 10,911,000 | 11,040,000 | 10,911,000 | 11,040,000 | ||||||
Appalachian Power Co [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,799,000 | 1,799,000 | 4,161,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,274,000 | 1,274,000 | 1,959,000 | |||||||
Appalachian Power Co [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 85,894,000 | 85,894,000 | 167,414,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 81,155,000 | 81,155,000 | 160,216,000 | |||||||
Appalachian Power Co [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 13,701,000 | 13,701,000 | 17,058,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 2,790,000 | 2,790,000 | 6,079,000 | |||||||
Appalachian Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -56,005,000 | -56,005,000 | -123,313,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -61,497,000 | -61,497,000 | -133,080,000 | |||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 45,082,000 | [10],[14] | 45,082,000 | [10],[14] | 65,018,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 23,292,000 | [10],[14] | 23,292,000 | [10],[14] | 33,819,000 | [10],[14] | ||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,799,000 | [10],[14] | 1,799,000 | [10],[14] | 4,161,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,274,000 | [10],[14] | 1,274,000 | [10],[14] | 1,959,000 | [10],[14] | ||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 85,442,000 | [10],[14] | 85,442,000 | [10],[14] | 166,916,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 80,580,000 | [10],[14] | 80,580,000 | [10],[14] | 158,665,000 | [10],[14] | ||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 13,701,000 | [10],[14] | 13,701,000 | [10],[14] | 17,058,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 2,790,000 | [10],[14] | 2,790,000 | [10],[14] | 6,079,000 | [10],[14] | ||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -55,860,000 | [10],[14] | -55,860,000 | [10],[14] | -123,117,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -61,352,000 | [10],[14] | -61,352,000 | [10],[14] | -132,884,000 | [10],[14] | ||||
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 11,506,000 | 11,506,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,940,000 | 1,940,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | 12.52 | 12.52 | ||||||||
Forward Price Range High | 55.4 | 55.4 | ||||||||
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 2,195,000 | 2,195,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 850,000 | 850,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | -5.26 | -5.26 | ||||||||
Forward Price Range High | 10.85 | 10.85 | ||||||||
Appalachian Power Co [Member] | Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 307,000 | [10] | 307,000 | [10] | 302,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 430,000 | [10] | 430,000 | [10] | 1,355,000 | [10] | ||||
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 452,000 | [10] | 452,000 | [10] | 498,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 575,000 | [10] | 575,000 | [10] | 1,551,000 | [10] | ||||
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Appalachian Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -145,000 | [10] | -145,000 | [10] | -196,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -145,000 | [10] | -145,000 | [10] | -196,000 | [10] | ||||
Indiana Michigan Power Co [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 29,883,000 | 29,883,000 | 50,543,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,839,118,000 | 1,839,118,000 | 1,705,772,000 | |||||||
Total Assets | 1,869,001,000 | 1,869,001,000 | 1,756,315,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 17,575,000 | 17,575,000 | 45,415,000 | |||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | ||||||||||
Beginning Balance | 8,967,000 | 9,049,000 | 7,541,000 | 1,263,000 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | -754,000 | [2],[3] | -2,440,000 | [2],[3] | -2,386,000 | [2],[3] | -3,488,000 | [2],[3] | ||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | 0 | [2] | 0 | [2] | 0 | [2] | 0 | [2] | ||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 277,000 | 0 | 211,000 | ||||||
Purchases, Issuances and Settlements | -757,000 | [4] | 635,000 | [4] | 1,213,000 | [4] | 7,325,000 | [4] | ||
Transfers into Level 3 | 9,000 | [5],[6] | 460,000 | [5],[6] | 661,000 | [5],[6] | 2,749,000 | [5],[6] | ||
Transfers out of Level 3 | -11,000 | [6],[7] | -202,000 | [6],[7] | -637,000 | [6],[7] | -3,193,000 | [6],[7] | ||
Changes in Fair Value Allocated to Regulated Jurisdictions | -275,000 | [8] | -193,000 | [8] | 787,000 | [8] | 2,719,000 | [8] | ||
Ending Balance | 7,179,000 | 7,586,000 | 7,179,000 | 7,586,000 | ||||||
Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,184,000 | 1,184,000 | 2,858,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 926,976,000 | 926,976,000 | 742,090,000 | |||||||
Total Assets | 928,160,000 | 928,160,000 | 744,948,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 838,000 | 838,000 | 1,346,000 | |||||||
Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 56,449,000 | 56,449,000 | 120,572,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,388,000 | 903,388,000 | 953,407,000 | |||||||
Total Assets | 959,837,000 | 959,837,000 | 1,073,979,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 55,278,000 | 55,278,000 | 131,206,000 | |||||||
Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 9,015,000 | 9,015,000 | 11,717,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Total Assets | 9,015,000 | 9,015,000 | 11,717,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,836,000 | 1,836,000 | 4,176,000 | |||||||
Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -36,765,000 | -36,765,000 | -84,604,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 8,754,000 | 8,754,000 | 10,275,000 | |||||||
Total Assets | -28,011,000 | -28,011,000 | -74,329,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -40,377,000 | -40,377,000 | -91,313,000 | |||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 29,684,000 | [10],[14] | 29,684,000 | [10],[14] | 50,343,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 17,297,000 | [10],[14] | 17,297,000 | [10],[14] | 24,960,000 | [10],[14] | ||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,184,000 | [10],[14] | 1,184,000 | [10],[14] | 2,858,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 838,000 | [10],[14] | 838,000 | [10],[14] | 1,346,000 | [10],[14] | ||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 56,155,000 | [10],[14] | 56,155,000 | [10],[14] | 120,242,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 54,905,000 | [10],[14] | 54,905,000 | [10],[14] | 110,621,000 | [10],[14] | ||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 9,015,000 | [10],[14] | 9,015,000 | [10],[14] | 11,717,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,836,000 | [10],[14] | 1,836,000 | [10],[14] | 4,176,000 | [10],[14] | ||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -36,670,000 | [10],[14] | -36,670,000 | [10],[14] | -84,474,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -40,282,000 | [10],[14] | -40,282,000 | [10],[14] | -91,183,000 | [10],[14] | ||||
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 7,571,000 | 7,571,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,276,000 | 1,276,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | 12.52 | 12.52 | ||||||||
Forward Price Range High | 55.4 | 55.4 | ||||||||
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,444,000 | 1,444,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 560,000 | 560,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | -5.26 | -5.26 | ||||||||
Forward Price Range High | 10.85 | 10.85 | ||||||||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 199,000 | [10] | 199,000 | [10] | 200,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 278,000 | [10] | 278,000 | [10] | 931,000 | [10] | ||||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 294,000 | [10] | 294,000 | [10] | 330,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 373,000 | [10] | 373,000 | [10] | 1,061,000 | [10] | ||||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -95,000 | [10] | -95,000 | [10] | -130,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -95,000 | [10] | -95,000 | [10] | -130,000 | [10] | ||||
Indiana Michigan Power Co [Member] | Interest Rate Foreign Currency Hedges [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 19,524,000 | |||||||||
Indiana Michigan Power Co [Member] | Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | |||||||||
Indiana Michigan Power Co [Member] | Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 19,524,000 | |||||||||
Indiana Michigan Power Co [Member] | Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | |||||||||
Indiana Michigan Power Co [Member] | Interest Rate Foreign Currency Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | |||||||||
Ohio Power Co [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 8,065,000 | [15] | 8,065,000 | [15] | 65,000 | [15] | ||||
Risk Management Assets | ||||||||||
Risk Management Assets | 62,772,000 | 62,772,000 | 92,601,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 70,837,000 | 70,837,000 | 92,666,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 33,008,000 | 33,008,000 | 50,120,000 | |||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | ||||||||||
Beginning Balance | 18,347,000 | 18,969,000 | 15,429,000 | 2,666,000 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | -1,616,000 | [2],[3] | -5,024,000 | [2],[3] | -4,879,000 | [2],[3] | -7,316,000 | [2],[3] | ||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | -89,000 | [2] | -1,030,000 | [2] | 351,000 | [2] | 4,973,000 | [2] | ||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 571,000 | 0 | 435,000 | ||||||
Purchases, Issuances and Settlements | -1,504,000 | [4] | 1,299,000 | [4] | 2,463,000 | [4] | 15,375,000 | [4] | ||
Transfers into Level 3 | 18,000 | [5],[6] | 964,000 | [5],[6] | 1,353,000 | [5],[6] | 5,789,000 | [5],[6] | ||
Transfers out of Level 3 | -21,000 | [6],[7] | -423,000 | [6],[7] | -1,303,000 | [6],[7] | -6,733,000 | [6],[7] | ||
Changes in Fair Value Allocated to Regulated Jurisdictions | -164,000 | [8] | 253,000 | [8] | 1,557,000 | [8] | 390,000 | [8] | ||
Ending Balance | 14,971,000 | 15,579,000 | 14,971,000 | 15,579,000 | ||||||
Ohio Power Co [Member] | Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 8,022,000 | [15] | 8,022,000 | [15] | 0 | [15] | ||||
Risk Management Assets | ||||||||||
Risk Management Assets | 2,469,000 | 2,469,000 | 5,848,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 10,491,000 | 10,491,000 | 5,848,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,748,000 | 1,748,000 | 2,753,000 | |||||||
Ohio Power Co [Member] | Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 26,000 | [15] | 26,000 | [15] | 26,000 | [15] | ||||
Risk Management Assets | ||||||||||
Risk Management Assets | 120,365,000 | 120,365,000 | 238,942,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 120,391,000 | 120,391,000 | 238,968,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 113,827,000 | 113,827,000 | 228,711,000 | |||||||
Ohio Power Co [Member] | Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 0 | [15] | 0 | [15] | 0 | [15] | ||||
Risk Management Assets | ||||||||||
Risk Management Assets | 18,799,000 | 18,799,000 | 23,973,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 18,799,000 | 18,799,000 | 23,973,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 3,828,000 | 3,828,000 | 8,544,000 | |||||||
Ohio Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 17,000 | [15] | 17,000 | [15] | 39,000 | [15] | ||||
Risk Management Assets | ||||||||||
Risk Management Assets | -78,861,000 | -78,861,000 | -176,162,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | -78,844,000 | -78,844,000 | -176,123,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -86,395,000 | -86,395,000 | -189,888,000 | |||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 62,354,000 | [10],[14] | 62,354,000 | [10],[14] | 92,185,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 32,423,000 | [10],[14] | 32,423,000 | [10],[14] | 48,217,000 | [10],[14] | ||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 2,469,000 | [10],[14] | 2,469,000 | [10],[14] | 5,848,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,748,000 | [10],[14] | 1,748,000 | [10],[14] | 2,753,000 | [10],[14] | ||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 119,749,000 | [10],[14] | 119,749,000 | [10],[14] | 238,254,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 113,044,000 | [10],[14] | 113,044,000 | [10],[14] | 226,536,000 | [10],[14] | ||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 18,799,000 | [10],[14] | 18,799,000 | [10],[14] | 23,973,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 3,828,000 | [10],[14] | 3,828,000 | [10],[14] | 8,544,000 | [10],[14] | ||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -78,663,000 | [10],[14] | -78,663,000 | [10],[14] | -175,890,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -86,197,000 | [10],[14] | -86,197,000 | [10],[14] | -189,616,000 | [10],[14] | ||||
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 15,787,000 | 15,787,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 2,661,000 | 2,661,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | 12.52 | 12.52 | ||||||||
Forward Price Range High | 55.4 | 55.4 | ||||||||
Ohio Power Co [Member] | FTRs [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 3,012,000 | 3,012,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,167,000 | 1,167,000 | ||||||||
Level 3 Quantitative Information [Abstract] | ||||||||||
Forward Price Range Low | -5.26 | -5.26 | ||||||||
Forward Price Range High | 10.85 | 10.85 | ||||||||
Ohio Power Co [Member] | Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 418,000 | [10] | 418,000 | [10] | 416,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 585,000 | [10] | 585,000 | [10] | 1,903,000 | [10] | ||||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 616,000 | [10] | 616,000 | [10] | 688,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 783,000 | [10] | 783,000 | [10] | 2,175,000 | [10] | ||||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Ohio Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -198,000 | [10] | -198,000 | [10] | -272,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -198,000 | [10] | -198,000 | [10] | -272,000 | [10] | ||||
Public Service Co Of Oklahoma [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,001,000 | 1,001,000 | 540,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,388,000 | 1,388,000 | 5,879,000 | |||||||
Public Service Co Of Oklahoma [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Public Service Co Of Oklahoma [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,553,000 | 1,553,000 | 1,699,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,947,000 | 1,947,000 | 7,038,000 | |||||||
Public Service Co Of Oklahoma [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Public Service Co Of Oklahoma [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -552,000 | -552,000 | -1,159,000 | |||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -559,000 | -559,000 | -1,159,000 | |||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 991,000 | [10],[14] | 991,000 | [10],[14] | 515,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,372,000 | [10],[14] | 1,372,000 | [10],[14] | 5,879,000 | [10],[14] | ||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,543,000 | [10],[14] | 1,543,000 | [10],[14] | 1,657,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,931,000 | [10],[14] | 1,931,000 | [10],[14] | 7,021,000 | [10],[14] | ||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -552,000 | [10],[14] | -552,000 | [10],[14] | -1,142,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -559,000 | [10],[14] | -559,000 | [10],[14] | -1,142,000 | [10],[14] | ||||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 10,000 | [10] | 10,000 | [10] | 25,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 16,000 | [10] | 16,000 | [10] | 0 | [10] | ||||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 10,000 | [10] | 10,000 | [10] | 42,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 16,000 | [10] | 16,000 | [10] | 17,000 | [10] | ||||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | -17,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | -17,000 | [10] | ||||
Southwestern Electric Power Co [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 17,651,000 | [15] | 17,651,000 | [15] | ||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 423,000 | 423,000 | 695,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 18,074,000 | 18,074,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 296,000 | 296,000 | 1,128,000 | |||||||
Southwestern Electric Power Co [Member] | Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 14,186,000 | [15] | 14,186,000 | [15] | ||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 14,186,000 | 14,186,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Southwestern Electric Power Co [Member] | Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 0 | [15] | 0 | [15] | ||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,476,000 | 1,476,000 | 2,845,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 1,476,000 | 1,476,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,357,000 | 1,357,000 | 3,278,000 | |||||||
Southwestern Electric Power Co [Member] | Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 0 | [15] | 0 | [15] | ||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 0 | 0 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | 0 | 0 | |||||||
Southwestern Electric Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Cash and Cash Equivalents | 3,465,000 | [15] | 3,465,000 | [15] | ||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -1,053,000 | -1,053,000 | -2,150,000 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Total Assets | 2,412,000 | 2,412,000 | ||||||||
Liabilities: | ||||||||||
Risk Management Liabilities | -1,061,000 | -1,061,000 | -2,150,000 | |||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 411,000 | [10],[14] | 411,000 | [10],[14] | 671,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 277,000 | [10],[14] | 277,000 | [10],[14] | 1,128,000 | [10],[14] | ||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 1,464,000 | [10],[14] | 1,464,000 | [10],[14] | 2,804,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 1,338,000 | [10],[14] | 1,338,000 | [10],[14] | 3,261,000 | [10],[14] | ||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10],[14] | 0 | [10],[14] | 0 | [10],[14] | ||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | -1,053,000 | [10],[14] | -1,053,000 | [10],[14] | -2,133,000 | [10],[14] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | -1,061,000 | [10],[14] | -1,061,000 | [10],[14] | -2,133,000 | [10],[14] | ||||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 12,000 | [10] | 12,000 | [10] | 24,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 19,000 | [10] | 19,000 | [10] | 0 | [10] | ||||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 12,000 | [10] | 12,000 | [10] | 41,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 19,000 | [10] | 19,000 | [10] | 17,000 | [10] | ||||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | 0 | [10] | ||||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [10] | 0 | [10] | -17,000 | [10] | ||||
Liabilities: | ||||||||||
Risk Management Liabilities | 0 | [10] | 0 | [10] | -17,000 | [10] | ||||
Cash [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 188,000,000 | [1] | 188,000,000 | [1] | 241,000,000 | [1] | ||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 15,000,000 | [16] | 15,000,000 | [16] | 17,000,000 | [16] | ||||
Cash [Member] | Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 173,000,000 | [1] | 173,000,000 | [1] | 227,000,000 | [1] | ||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 6,000,000 | [16] | 6,000,000 | [16] | 7,000,000 | [16] | ||||
Cash [Member] | Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 7,000,000 | [1] | 7,000,000 | [1] | 5,000,000 | [1] | ||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [16] | 0 | [16] | 0 | [16] | ||||
Cash [Member] | Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | [1] | 0 | [1] | 0 | [1] | ||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [16] | 0 | [16] | 0 | [16] | ||||
Cash [Member] | Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 8,000,000 | [1] | 8,000,000 | [1] | 9,000,000 | [1] | ||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 9,000,000 | [16] | 9,000,000 | [16] | 10,000,000 | [16] | ||||
Cash [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 14,438,000 | [17] | 14,438,000 | [17] | 16,783,000 | [17] | ||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 5,684,000 | [17] | 5,684,000 | [17] | 6,508,000 | [17] | ||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [17] | 0 | [17] | 0 | [17] | ||||
Cash [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [17] | 0 | [17] | 0 | [17] | ||||
Cash [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 8,754,000 | [17] | 8,754,000 | [17] | 10,275,000 | [17] | ||||
Fixed Income Funds [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,000,000 | 903,000,000 | 953,000,000 | |||||||
Fixed Income Funds [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,000,000 | 903,000,000 | 953,000,000 | |||||||
Fixed Income Funds [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,388,000 | 903,388,000 | 953,407,000 | |||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 903,388,000 | 903,388,000 | 953,407,000 | |||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Mutual Funds Fixed Income [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 79,000,000 | 79,000,000 | 67,000,000 | |||||||
Mutual Funds Fixed Income [Member] | Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 79,000,000 | 79,000,000 | 67,000,000 | |||||||
Mutual Funds Fixed Income [Member] | Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | 0 | 0 | |||||||
Mutual Funds Fixed Income [Member] | Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | 0 | 0 | |||||||
Mutual Funds Fixed Income [Member] | Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | 0 | 0 | |||||||
Domestic [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 921,000,000 | [18] | 921,000,000 | [18] | 736,000,000 | [18] | ||||
Domestic [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 921,000,000 | [18] | 921,000,000 | [18] | 736,000,000 | [18] | ||||
Domestic [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Domestic [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Domestic [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Domestic [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 921,292,000 | [18] | 921,292,000 | [18] | 735,582,000 | [18] | ||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 921,292,000 | [18] | 921,292,000 | [18] | 735,582,000 | [18] | ||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Mutual Funds Equity [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 21,000,000 | [18] | 21,000,000 | [18] | 16,000,000 | [18] | ||||
Mutual Funds Equity [Member] | Level 1 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 21,000,000 | [18] | 21,000,000 | [18] | 16,000,000 | [18] | ||||
Mutual Funds Equity [Member] | Level 2 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Mutual Funds Equity [Member] | Level 3 [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Mutual Funds Equity [Member] | Fair Value Inputs Other [Member] | ||||||||||
Assets: | ||||||||||
Other Temporary Investments | 0 | [18] | 0 | [18] | 0 | [18] | ||||
Cash and Cash Equivalents [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 15,000,000 | 15,000,000 | 17,000,000 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 14,438,000 | 14,438,000 | 16,783,000 | |||||||
US Government Agencies Debt Securities [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 621,000,000 | 621,000,000 | 648,000,000 | |||||||
US Government Agencies Debt Securities [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 621,000,000 | 621,000,000 | 648,000,000 | |||||||
US Government Agencies Debt Securities [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 620,944,000 | 620,944,000 | 647,918,000 | |||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 620,944,000 | 620,944,000 | 647,918,000 | |||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 38,000,000 | 38,000,000 | 35,000,000 | |||||||
Corporate Debt [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 38,000,000 | 38,000,000 | 35,000,000 | |||||||
Corporate Debt [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 38,272,000 | 38,272,000 | 35,399,000 | |||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 38,272,000 | 38,272,000 | 35,399,000 | |||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 244,000,000 | 244,000,000 | 270,000,000 | |||||||
State and Local Jurisdiction [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 244,000,000 | 244,000,000 | 270,000,000 | |||||||
State and Local Jurisdiction [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 244,172,000 | 244,172,000 | 270,090,000 | |||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 244,172,000 | 244,172,000 | 270,090,000 | |||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | ||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | |||||||
Dedesignated Risk Management Contracts [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 9,000,000 | [19] | 9,000,000 | [19] | 14,000,000 | [19] | ||||
Dedesignated Risk Management Contracts [Member] | Level 1 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [19] | 0 | [19] | 0 | [19] | ||||
Dedesignated Risk Management Contracts [Member] | Level 2 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [19] | 0 | [19] | 0 | [19] | ||||
Dedesignated Risk Management Contracts [Member] | Level 3 [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | 0 | [19] | 0 | [19] | 0 | [19] | ||||
Dedesignated Risk Management Contracts [Member] | Fair Value Inputs Other [Member] | ||||||||||
Risk Management Assets | ||||||||||
Risk Management Assets | $9,000,000 | [19] | $9,000,000 | [19] | $14,000,000 | [19] | ||||
[1] | Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||
[2] | Included in revenues on the condensed statements of income. | |||||||||
[3] | Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. | |||||||||
[4] | Represents the settlement of risk management commodity contracts for the reporting period. | |||||||||
[5] | Represents existing assets or liabilities that were previously categorized as Level 2. | |||||||||
[6] | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | |||||||||
[7] | Represents existing assets or liabilities that were previously categorized as Level 3. | |||||||||
[8] | Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets. | |||||||||
[9] | Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. | |||||||||
[10] | 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.'' | |||||||||
[11] | The September 30, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $1 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $4 million in 2013, $48 million in periods 2014-2016, $8 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $6 million in 2013, $60 million in periods 2014-2016, $32 million in periods 2017-2018 and $25 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||
[12] | The December 31, 2012 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $9 million in 2013, ($3) million in periods 2014-2016 and ($4) million in periods 2017-2018; Level 2 matures $16 million in 2013, $61 million in periods 2014-2016, $16 million in periods 2017-2018 and $7 million in periods 2019-2030; Level 3 matures $18 million in 2013, $31 million in periods 2014-2016, $13 million in periods 2017-2018 and $24 million in periods 2019-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||
[13] | Represents market prices in dollars per MWh. | |||||||||
[14] | Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||
[15] | Amounts in bOtherb column primarily represent cash deposits with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. | |||||||||
[16] | Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||
[17] | Amounts in bOtherb column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||
[18] | Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||
[19] | Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts. |
Income_Taxes_Details
Income Taxes (Details) (USD $) | 3 Months Ended | 9 Months Ended | 6 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | |||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Jun. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | |
Uk Windfall Tax Issue [Member] | Uk Windfall Tax Issue [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | |||||
Income Taxes (Textuals) [Abstract] | ||||||||||||||||||||||||||
Reduction in Expected Future Cash Flow | ($10,000,000) | |||||||||||||||||||||||||
Original WV Corporate Income Tax Rate | 7.00% | 7.00% | 7.00% | 7.00% | ||||||||||||||||||||||
Reduced WV Corporate Income Tax Rate | 6.50% | 6.50% | 6.50% | 6.50% | ||||||||||||||||||||||
Income Tax Benefit | -257,000,000 | -241,000,000 | -520,000,000 | -620,000,000 | 80,000,000 | -41,645,000 | -34,185,000 | -108,554,000 | -120,377,000 | -27,953,000 | -16,974,000 | -69,102,000 | -45,755,000 | -93,141,000 | -82,578,000 | -174,313,000 | -213,290,000 | -32,217,000 | -35,355,000 | -58,778,000 | -64,872,000 | -14,935,000 | -25,229,000 | -37,057,000 | -49,206,000 | |
Interest and Investment Income | 3,000,000 | 2,000,000 | 55,000,000 | 6,000,000 | 43,000,000 | |||||||||||||||||||||
Net Income (Loss) | 434,000,000 | 488,000,000 | 1,137,000,000 | 1,241,000,000 | 108,000,000 | 62,625,000 | 63,191,000 | 163,035,000 | 200,834,000 | 57,880,000 | 39,254,000 | 142,091,000 | 108,285,000 | 178,901,000 | 151,510,000 | 329,731,000 | 403,763,000 | 51,096,000 | 58,103,000 | 93,221,000 | 105,962,000 | 7,920,000 | 89,218,000 | 49,695,000 | 180,515,000 | |
Unrecognized Tax Benefits | $64,000,000 |
Financing_Activities_Details
Financing Activities (Details) (USD $) | 3 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 1 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | 3 Months Ended | 9 Months Ended | 9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Oct. 25, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | Sep. 30, 2013 | Sep. 30, 2013 | Sep. 30, 2013 | ||||||||||||||
Long-term Debt [Member] | Long Term Debt Two [Member] | AEP Subsidiaries [Member] | AEP Subsidiaries [Member] | AEP Subsidiaries [Member] | AEP Subsidiaries [Member] | AEP Generating Co [Member] | Kentucky Power Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central Co [Member] | AEP Texas North Co [Member] | AEP Texas North Co [Member] | AEP Texas North Co [Member] | AEP Texas North Co [Member] | AEP Texas North Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Public Service Co Of Oklahoma [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | AEP Transmission Company, LLC [Member] | AEP Generating Co, Appalachian Power Co, Kentucky Power Co, Ohio Power Co | |||||||||||||||||||
Notes Payable One [Member] | Notes Payable Two [Member] | Senior Unsecured Notes One [Member] | Securitization Bonds One [Member] | Securitization Bonds Two [Member] | Securitization Bonds Three [Member] | Securitization Bonds Four [Member] | Pollution Control Bonds One [Member] | Long-term Debt [Member] | Senior Unsecured Notes One [Member] | Senior Unsecured Notes Two [Member] | Senior Unsecured Notes Three [Member] | Long-term Debt [Member] | Pollution Control Bonds One [Member] | Pollution Control Bonds Two [Member] | Pollution Control Bonds Three [Member] | Pollution Control Bonds Four [Member] | Senior Unsecured Notes One [Member] | Land Note [Member] | Notes Payable One [Member] | Notes Payable One [Member] | Notes Payable Two [Member] | Notes Payable Three [Member] | Notes Payable Four [Member] | Notes Payable Five [Member] | Notes Payable Six [Member] | Notes Payable Seven [Member] | Notes Payable Eight [Member] | Pollution Control Bonds One [Member] | Senior Unsecured Notes One [Member] | Long-term Debt [Member] | Long Term Debt Two [Member] | Securitization Bonds One [Member] | Securitization Bonds Two [Member] | Pollution Control Bonds One [Member] | Pollution Control Bonds Two [Member] | Pollution Control Bonds Three [Member] | Pollution Control Bonds Four [Member] | Pollution Control Bonds Five [Member] | Senior Unsecured Notes One [Member] | Senior Unsecured Notes Two [Member] | Senior Unsecured Notes Three [Member] | Senior Unsecured Notes Four [Member] | Long-term Debt [Member] | Long Term Debt Two [Member] | Long Term Debt Three [Member] | Notes Payable One [Member] | Notes Payable One [Member] | Senior Unsecured Notes One [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Senior Unsecured Notes | $11,705,000,000 | $11,705,000,000 | $12,712,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pollution Control Bonds | 1,982,000,000 | 1,982,000,000 | 1,958,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Notes Payable | 425,000,000 | 425,000,000 | 427,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Securitization Bonds | 2,338,000,000 | 2,338,000,000 | 2,281,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Spent Nuclear Fuel Obligation | 265,000,000 | [1] | 265,000,000 | [1] | 265,000,000 | [1] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Other Long-term Debt | 886,000,000 | 886,000,000 | 140,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value of Interest Rate Hedges | -7,000,000 | -7,000,000 | 3,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unamortized Discount, Net | -26,000,000 | -26,000,000 | -29,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Long-term Debt Outstanding | 17,568,000,000 | 17,568,000,000 | 17,757,000,000 | 3,427,917,000 | 3,427,917,000 | 3,702,442,000 | 2,271,613,000 | 2,271,613,000 | 2,057,666,000 | 3,698,574,000 | 3,698,574,000 | 3,860,440,000 | 949,826,000 | 949,826,000 | 949,871,000 | 2,043,244,000 | 2,043,244,000 | 2,046,228,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt Due Within One Year | 1,366,000,000 | 1,366,000,000 | 2,171,000,000 | 433,000,000 | 367,000,000 | 229,682,000 | 229,682,000 | 574,679,000 | 224,859,000 | 224,859,000 | 203,953,000 | 553,516,000 | 553,516,000 | 856,000,000 | 34,111,000 | 34,111,000 | 764,000 | 3,250,000 | 3,250,000 | 3,250,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt | 16,202,000,000 | 16,202,000,000 | 15,586,000,000 | 2,222,000,000 | 2,227,000,000 | 3,198,235,000 | 3,198,235,000 | 3,127,763,000 | 2,046,754,000 | 2,046,754,000 | 1,853,713,000 | 2,945,058,000 | 2,945,058,000 | 2,804,440,000 | 915,715,000 | 915,715,000 | 949,107,000 | 2,039,994,000 | 2,039,994,000 | 2,042,978,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Issuances | 2,098,000,000 | [2] | 200,000,000 | [3] | 120,000,000 | 75,000,000 | [4] | 125,000,000 | 75,000,000 | 75,000,000 | [5] | 30,000,000 | 40,000,000 | 101,354,000 | 250,000,000 | 164,900,000 | 102,508,000 | 50,000,000 | 65,000,000 | 200,000,000 | [6] | 600,000,000 | [7] | 25,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirements and Principal Payments | 2,281,000,000 | 904,000,000 | 200,000,000 | [3] | 5,000,000 | 2,000,000 | 7,000,000 | 76,000,000 | 67,000,000 | 42,000,000 | 26,000,000 | 225,000,000 | 345,021,000 | 364,868,000 | 30,000,000 | 40,000,000 | 275,000,000 | 21,000 | 137,544,000 | 78,062,000 | 37,000,000 | 9,811,000 | 12,071,000 | 14,945,000 | 10,350,000 | 31,289,000 | 8,204,000 | 6,083,000 | 40,000,000 | 705,000 | 4,086,000 | 1,146,000,000 | 194,500,000 | 65,000,000 | 56,000,000 | 50,000,000 | 250,000,000 | 250,000,000 | 250,000,000 | 225,000,000 | 200,000,000 | [6] | 301,000 | 130,000 | 301,000 | 3,250,000 | 21,625,000 | 3,250,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate (Percentage) | 6.33% | 4.98% | 5.96% | 5.09% | 0.88% | 4.00% | 3.09% | 4.48% | 5.50% | 3.25% | 3.25% | 4.85% | 4.85% | 13.72% | 4.00% | 2.12% | 5.44% | 5.25% | 3.20% | 6.00% | 0.96% | 2.05% | 4.90% | 5.10% | 5.15% | 5.50% | 5.50% | 5.75% | 6.38% | 3.00% | 4.58% | 4.83% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate (Variable) | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | Variable | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Due Date | 2015 | 2015 | 2017 | 2026 | 2037 | 2013 | 2013 | 2015 | 2017 | 2030 | 2016 | 2023 | 2043 | 2013 | 2016 | 2018 | 2018 | 2013 | 2013 | 2013 | 2026 | 2017 | 2014 | 2015 | 2016 | 2016 | 2016 | 2017 | 2013 | 2025 | 2023 | 2025 | 2015 | 2018 | 2020 | 2014 | 2014 | 2037 | 2013 | 2026 | 2013 | 2013 | 2013 | 2033 | 2015 | 2015 | 2015 | 2027 | 2032 | 2043 | ||||||||||||||||||||||||||||||||||||||||||||||||||
Long- term Debt by Type of Debt and Maturity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate (Minimum) | 7.59% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Interest Rate (Maximum) | 8.03% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Borrowings from Utility Money Pool | 331,771,000 | 23,135,000 | 410,456,000 | 46,806,000 | 15,386,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Loans to Utility Money Pool | 39,372,000 | 384,435,000 | 415,605,000 | 52,734,000 | 153,830,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Borrowings from Utility Money Pool | 126,391,000 | 8,308,000 | 228,719,000 | 18,658,000 | 4,154,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Loans to Utility Money Pool | 23,632,000 | 239,647,000 | 59,047,000 | 18,808,000 | 38,449,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Loans (Borrowings) to/from Utility Money Pool | -253,352,000 | -253,352,000 | 322,476,000 | 322,476,000 | 9,401,000 | 9,401,000 | 19,442,000 | 19,442,000 | 18,634,000 | 18,634,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Authorized Short-term Borrowing Limit | 600,000,000 | 500,000,000 | 600,000,000 | 300,000,000 | 350,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nonutility Money Pool Particpants' Money Pool Activity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Borrowings from Nonutility Money Pool | 1,047,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Loans to Nonutility Money Pool | 1,027,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Borrowings from Nonutility Money Pool | 201,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Loans to Nonutility Money Pool | 208,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Borrowings from Nonutility Money Pool | 338,000 | 338,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum and Minimum Interest Rates | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Interest Rate | 0.43% | 0.56% | 0.43% | 0.56% | 0.43% | 0.56% | 0.43% | 0.56% | 0.43% | 0.56% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Interest Rate | 0.28% | 0.44% | 0.28% | 0.44% | 0.28% | 0.44% | 0.28% | 0.44% | 0.28% | 0.44% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Interest Rate for Funds Borrowed | 0.33% | 0.48% | 0.36% | 0.00% | 0.34% | 0.47% | 0.34% | 0.00% | 0.33% | 0.53% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Interest Rate for Funds Loaned | 0.34% | 0.48% | 0.33% | 0.47% | 0.32% | 0.50% | 0.32% | 0.47% | 0.36% | 0.47% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum, Miminum, Average Interest Rates for Funds Borrowed from or Loaned to Nonutility Money Pool | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Interest Rate for Funds Borrowed from Nonutility Money Pool | 0.61% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Interest Rate for Funds Borrowed from Nonutility Money Pool | 0.53% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Interest Rate for Funds Loaned to Nonutility Money Pool | 0.35% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Minimum Interest Rate for Funds Loaned to Nonutility Money Pool | 0.32% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Interest Rate for Funds Borrowed | 0.56% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Average Interest Rate for Funds Loaned | 0.34% | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Short-term Debt: | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Securitized Debt for Receivables | 700,000,000 | [8] | 700,000,000 | [8] | 657,000,000 | [8] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commercial Paper | 518,000,000 | 518,000,000 | 321,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit - Sabine | 0 | [9] | 0 | [9] | 3,000,000 | [9] | 0 | 0 | 2,603,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Short-term Debt | 1,218,000,000 | 1,218,000,000 | 981,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Securitized Debt for Receivables | 0.23% | [10] | 0.23% | [10] | 0.26% | [10] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commercial Paper | 0.31% | [10] | 0.31% | [10] | 0.42% | [10] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Line of Credit - Sabine | 0.00% | [10] | 0.00% | [10] | 1.82% | [10] | 0.00% | [10] | 0.00% | [10] | 1.82% | [10] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Comparative Accounts Receivable Information | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Effective Interest Rates on Securitization of Accounts Receivable | 0.23% | 0.26% | 0.23% | 0.26% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Uncollectible Accounts Receivable Written Off | 12,000,000 | 8,000,000 | 26,000,000 | 21,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Customer Accounts Receivable Managed Portfolio | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | 965,000,000 | 965,000,000 | 835,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Principal Outstanding | 700,000,000 | 700,000,000 | 657,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Delinquent Securitized Accounts Receivable | 60,000,000 | 60,000,000 | 37,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable | 17,000,000 | 17,000,000 | 21,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable | 266,000,000 | 266,000,000 | 316,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | 135,579,000 | 135,579,000 | 153,719,000 | 143,804,000 | 143,804,000 | 123,447,000 | 321,054,000 | 321,054,000 | 300,675,000 | 147,586,000 | 147,586,000 | 85,530,000 | 180,922,000 | 180,922,000 | 132,449,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1,575,000 | 1,703,000 | 4,590,000 | 5,389,000 | 1,762,000 | 1,674,000 | 4,744,000 | 4,738,000 | 5,076,000 | 5,362,000 | 14,440,000 | 15,900,000 | 1,549,000 | 1,990,000 | 4,314,000 | 5,547,000 | 1,649,000 | 1,786,000 | 4,413,000 | 4,720,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proceeds from Sale of Receivables | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Proceeds from Sale of Receivables to AEP Credit | 340,438,000 | 351,570,000 | 1,081,615,000 | 993,975,000 | 384,316,000 | 358,936,000 | 1,097,563,000 | 1,018,933,000 | 658,829,000 | 790,115,000 | 2,017,746,000 | 2,284,749,000 | 382,167,000 | 342,819,000 | 944,062,000 | 919,343,000 | 450,294,000 | 444,461,000 | 1,171,306,000 | 1,145,182,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Financing Activities (Textuals) [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term Credit Facility | 1,000,000 | 1,000,000 | 1,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Term Credit Facility Maximum Borrowing | 250,000,000 | 500,000,000 | 500,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Revolving Credit Facilities | 100,000,000 | 75,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reacquired Pollution Controls Bonds Held by Trustees | 500,000,000 | 500,000,000 | 40,000,000 | 40,000,000 | 460,000,000 | 460,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Maximum Percentage Debt to Capitalization | 67.50% | 67.50% | 67.50% | 67.50% | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitment from Bank Conduits that Expire in One Year | 385,000,000 | 385,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commitment from Bank Conduits that Expire in Two Years | 315,000,000 | 315,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total Commitment from Bank Conduits to Finance Receivables | 700,000,000 | 700,000,000 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition | $309,000,000 | $309,000,000 | $308,000,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[1] | Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $308 million as of September 30, 2013 and December 31, 2012, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[2] | Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[3] | Draw on a $1 billion term credit facility that was terminated in July 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[4] | Draw on a $100 million three-year revolving credit facility to be used for general corporate purposes. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[5] | Draw on a $75 million three-year revolving credit facility to be used for general corporate purposes. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[6] | Intercompany issuance from AEP consisting of a draw on a $1 billion term credit facility that was terminated in July 2013. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[7] | Draw on a $1 billion term credit facility due in May 2015. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[8] | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[9] | This line of credit does not reduce available liquidity under AEP's credit facilities. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
[10] | Weighted average rate. |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 3 Months Ended | 9 Months Ended | ||||||
Sep. 30, 2013 | Sep. 30, 2012 | Sep. 30, 2013 | Sep. 30, 2012 | Dec. 31, 2012 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Securitization Bonds | $2,338,000,000 | $2,338,000,000 | $2,281,000,000 | |||||
Securitized Transition Assets | 2,080,000,000 | 2,080,000,000 | 2,117,000,000 | |||||
Percentage Ownership of "Allegheny Series" by a Nonaffiliated Company | 100.00% | |||||||
Sabine Mining Co [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 41,000,000 | 35,000,000 | 125,000,000 | 126,000,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 41,000,000 | 35,000,000 | 125,000,000 | 126,000,000 | ||||
DCC Fuel [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Payments Made by I&M to DCC Fuel | 32,000,000 | 23,000,000 | 96,000,000 | 82,000,000 | ||||
AEP Credit, Inc. [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Minimum Percentage of Equity AEP Provides | 5.00% | |||||||
Percentage of Short Term Borrowing Needs in Excess of Third Party Financings | 20.00% | |||||||
AEP Texas Central Transition Funding Co [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Securitization Bonds | 2,100,000,000 | 2,100,000,000 | 2,300,000,000 | |||||
Securitized Transition Assets | 1,900,000,000 | 1,900,000,000 | 2,100,000,000 | |||||
Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Insurance Premium Expense to Protected Cell | 15,000,000 | 16,000,000 | 30,000,000 | 31,000,000 | ||||
Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 9,000,000 | 9,000,000 | 9,000,000 | |||||
Maximum Exposure | 54,000,000 | 54,000,000 | 58,000,000 | |||||
Billings from Affiliates | ||||||||
Billings from VIE | 21,000,000 | 20,000,000 | 53,000,000 | 54,000,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 21,000,000 | 20,000,000 | 53,000,000 | 54,000,000 | ||||
Percentage of VIE Sales of Lignite Produced | 50.00% | |||||||
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO | 50.00% | |||||||
Percentage of Management Fee Received by SWEPCo from DHLC | 100.00% | |||||||
PATH West Virginia Transmission Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 33,000,000 | 33,000,000 | 31,000,000 | |||||
Maximum Exposure | 33,000,000 | 33,000,000 | 31,000,000 | |||||
Capital Contribution From Parent [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 8,000,000 | 8,000,000 | 8,000,000 | |||||
Maximum Exposure | 8,000,000 | 8,000,000 | 8,000,000 | |||||
Capital Contribution From Parent [Member] | PATH West Virginia Transmission Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 19,000,000 | 19,000,000 | 19,000,000 | |||||
Maximum Exposure | 19,000,000 | 19,000,000 | 19,000,000 | |||||
Retained Earnings [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 1,000,000 | 1,000,000 | 1,000,000 | |||||
Maximum Exposure | 1,000,000 | 1,000,000 | 1,000,000 | |||||
Retained Earnings [Member] | PATH West Virginia Transmission Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 14,000,000 | 14,000,000 | 12,000,000 | |||||
Maximum Exposure | 14,000,000 | 14,000,000 | 12,000,000 | |||||
SWEPCo's Guarantee Of Debt [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 0 | 0 | 0 | |||||
Maximum Exposure | 45,000,000 | 45,000,000 | 49,000,000 | |||||
Current Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 65,000,000 | 65,000,000 | 57,000,000 | |||||
Current Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 155,000,000 | 155,000,000 | 133,000,000 | |||||
Current Assets [Member] | AEP Credit, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 972,000,000 | 972,000,000 | 843,000,000 | |||||
Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 197,000,000 | 197,000,000 | 250,000,000 | |||||
Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 12,000,000 | 12,000,000 | ||||||
Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 146,000,000 | 146,000,000 | 130,000,000 | |||||
Net Property Plant And Equipment [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 160,000,000 | 160,000,000 | 170,000,000 | |||||
Net Property Plant And Equipment [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 181,000,000 | 181,000,000 | 176,000,000 | |||||
Net Property Plant And Equipment [Member] | AEP Credit, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 0 | 0 | 0 | |||||
Net Property Plant And Equipment [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 0 | 0 | 0 | |||||
Net Property Plant And Equipment [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 0 | 0 | ||||||
Net Property Plant And Equipment [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 0 | 0 | 0 | |||||
Other Non Current Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 56,000,000 | 56,000,000 | 55,000,000 | |||||
Other Non Current Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 79,000,000 | 79,000,000 | 92,000,000 | |||||
Other Non Current Assets [Member] | AEP Credit, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 1,000,000 | 1,000,000 | 1,000,000 | |||||
Other Non Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 1,989,000,000 | [1] | 1,989,000,000 | [1] | 2,167,000,000 | [2] | ||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Intercompany Item Eliminated in Consolidation | 84,000,000 | 84,000,000 | 89,000,000 | |||||
Other Non Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 261,000,000 | [3] | 261,000,000 | [3] | ||||
Other Non Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 4,000,000 | 4,000,000 | 4,000,000 | |||||
Total Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 281,000,000 | 281,000,000 | 282,000,000 | |||||
Total Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 415,000,000 | 415,000,000 | 401,000,000 | |||||
Total Assets [Member] | AEP Credit, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 973,000,000 | 973,000,000 | 844,000,000 | |||||
Total Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 2,186,000,000 | 2,186,000,000 | 2,417,000,000 | |||||
Total Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 273,000,000 | 273,000,000 | ||||||
Total Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
ASSETS | ||||||||
Assets | 150,000,000 | 150,000,000 | 134,000,000 | |||||
Current Liabilities [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 32,000,000 | 32,000,000 | 32,000,000 | |||||
Current Liabilities [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 139,000,000 | 139,000,000 | 121,000,000 | |||||
Current Liabilities [Member] | AEP Credit, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 856,000,000 | 856,000,000 | 800,000,000 | |||||
Current Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 298,000,000 | 298,000,000 | 304,000,000 | |||||
Current Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 36,000,000 | 36,000,000 | ||||||
Current Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 46,000,000 | 46,000,000 | 43,000,000 | |||||
Noncurrent Liabilities [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 249,000,000 | 249,000,000 | 250,000,000 | |||||
Noncurrent Liabilities [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 276,000,000 | 276,000,000 | 280,000,000 | |||||
Noncurrent Liabilities [Member] | AEP Credit, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 1,000,000 | 1,000,000 | 1,000,000 | |||||
Noncurrent Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 1,870,000,000 | 1,870,000,000 | 2,095,000,000 | |||||
Noncurrent Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 236,000,000 | 236,000,000 | ||||||
Noncurrent Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 70,000,000 | 70,000,000 | 66,000,000 | |||||
Equity [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 0 | 0 | 0 | |||||
Equity [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 0 | 0 | 0 | |||||
Equity [Member] | AEP Credit, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 116,000,000 | 116,000,000 | 43,000,000 | |||||
Equity [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 18,000,000 | 18,000,000 | 18,000,000 | |||||
Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 1,000,000 | 1,000,000 | ||||||
Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 34,000,000 | 34,000,000 | 25,000,000 | |||||
Total Liabilities And Equity [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 281,000,000 | 281,000,000 | 282,000,000 | |||||
Total Liabilities And Equity [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 415,000,000 | 415,000,000 | 401,000,000 | |||||
Total Liabilities And Equity [Member] | AEP Credit, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 973,000,000 | 973,000,000 | 844,000,000 | |||||
Total Liabilities And Equity [Member] | AEP Texas Central Transition Funding Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 2,186,000,000 | 2,186,000,000 | 2,417,000,000 | |||||
Total Liabilities And Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 273,000,000 | 273,000,000 | ||||||
Total Liabilities And Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 150,000,000 | 150,000,000 | 134,000,000 | |||||
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 39,779,000 | 47,820,000 | 120,315,000 | 130,260,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 39,779,000 | 47,820,000 | 120,315,000 | 130,260,000 | ||||
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 7,637,000 | 7,637,000 | 29,819,000 | |||||
Maximum Exposure | 7,637,000 | 7,637,000 | 29,819,000 | |||||
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Payments Made by I&M to DCC Fuel | 32,000,000 | 23,000,000 | 96,000,000 | 82,000,000 | ||||
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 66,114,000 | 65,051,000 | 177,840,000 | 177,790,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 66,114,000 | 65,051,000 | 177,840,000 | 177,790,000 | ||||
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 25,988,000 | 31,134,000 | 82,192,000 | 88,618,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 25,988,000 | 31,134,000 | 82,192,000 | 88,618,000 | ||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 6,560,000 | 6,560,000 | 17,911,000 | |||||
Maximum Exposure | 6,560,000 | 6,560,000 | 17,911,000 | |||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 26,323,000 | 26,323,000 | 25,498,000 | |||||
Maximum Exposure | 26,323,000 | 26,323,000 | 25,498,000 | |||||
Indiana Michigan Power Co [Member] | Current Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 155,448,000 | 155,448,000 | 132,886,000 | |||||
Indiana Michigan Power Co [Member] | Net Property Plant And Equipment [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 180,541,000 | 180,541,000 | 176,065,000 | |||||
Indiana Michigan Power Co [Member] | Other Non Current Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 78,689,000 | 78,689,000 | 92,473,000 | |||||
Indiana Michigan Power Co [Member] | Total Assets [Member] | DCC Fuel [Member] | ||||||||
ASSETS | ||||||||
Assets | 414,678,000 | 414,678,000 | 401,424,000 | |||||
Indiana Michigan Power Co [Member] | Current Liabilities [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 138,796,000 | 138,796,000 | 120,873,000 | |||||
Indiana Michigan Power Co [Member] | Noncurrent Liabilities [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 275,882,000 | 275,882,000 | 280,551,000 | |||||
Indiana Michigan Power Co [Member] | Total Liabilities And Equity [Member] | DCC Fuel [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 414,678,000 | 414,678,000 | 401,424,000 | |||||
Ohio Power Co [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Securitized Transition Assets | 136,566,000 | 136,566,000 | 0 | |||||
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Securitization Bonds | 267,000,000 | 267,000,000 | ||||||
Securitized Transition Assets | 137,000,000 | 137,000,000 | ||||||
Ohio Power Co [Member] | Billings from AEP Generating Co [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 37,255,000 | 46,184,000 | 107,876,000 | 149,424,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 37,255,000 | 46,184,000 | 107,876,000 | 149,424,000 | ||||
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 58,528,000 | 72,751,000 | 169,949,000 | 193,686,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 58,528,000 | 72,751,000 | 169,949,000 | 193,686,000 | ||||
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 14,217,000 | 14,217,000 | 39,323,000 | |||||
Maximum Exposure | 14,217,000 | 14,217,000 | 39,323,000 | |||||
Ohio Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 9,708,000 | 9,708,000 | 16,302,000 | |||||
Maximum Exposure | 9,708,000 | 9,708,000 | 16,302,000 | |||||
Ohio Power Co [Member] | Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 12,021,000 | 12,021,000 | ||||||
Ohio Power Co [Member] | Other Non Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 261,005,000 | [3] | 261,005,000 | [3] | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Intercompany Item Eliminated in Consolidation | 121,000,000 | 121,000,000 | ||||||
Ohio Power Co [Member] | Total Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
ASSETS | ||||||||
Assets | 273,026,000 | 273,026,000 | ||||||
Ohio Power Co [Member] | Current Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 35,550,000 | 35,550,000 | ||||||
Ohio Power Co [Member] | Noncurrent Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 236,139,000 | 236,139,000 | ||||||
Ohio Power Co [Member] | Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 1,337,000 | 1,337,000 | ||||||
Ohio Power Co [Member] | Total Liabilities And Equity [Member] | Ohio Phase-In-Recovery Funding [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 273,026,000 | 273,026,000 | ||||||
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 19,535,000 | 21,728,000 | 57,504,000 | 60,625,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 19,535,000 | 21,728,000 | 57,504,000 | 60,625,000 | ||||
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 4,710,000 | 4,710,000 | 13,381,000 | |||||
Maximum Exposure | 4,710,000 | 4,710,000 | 13,381,000 | |||||
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 41,000,000 | 35,000,000 | 125,000,000 | 126,000,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 41,000,000 | 35,000,000 | 125,000,000 | 126,000,000 | ||||
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 8,745,000 | 8,745,000 | 8,589,000 | |||||
Maximum Exposure | 53,642,000 | 53,642,000 | 58,153,000 | |||||
Billings from Affiliates | ||||||||
Billings from VIE | 21,000,000 | 20,000,000 | 53,000,000 | 54,000,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 21,000,000 | 20,000,000 | 53,000,000 | 54,000,000 | ||||
Percentage of VIE Sales of Lignite Produced | 50.00% | |||||||
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO | 50.00% | |||||||
Percentage of Management Fee Received by SWEPCo from DHLC | 100.00% | |||||||
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ||||||||
Billings from Affiliates | ||||||||
Billings from VIE | 28,431,000 | 33,154,000 | 85,506,000 | 93,120,000 | ||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Billings from VIE | 28,431,000 | 33,154,000 | 85,506,000 | 93,120,000 | ||||
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 6,778,000 | 6,778,000 | 19,669,000 | |||||
Maximum Exposure | 6,778,000 | 6,778,000 | 19,669,000 | |||||
Southwestern Electric Power Co [Member] | Capital Contribution From Parent [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 7,643,000 | 7,643,000 | 7,643,000 | |||||
Maximum Exposure | 7,643,000 | 7,643,000 | 7,643,000 | |||||
Southwestern Electric Power Co [Member] | Retained Earnings [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 1,102,000 | 1,102,000 | 946,000 | |||||
Maximum Exposure | 1,102,000 | 1,102,000 | 946,000 | |||||
Southwestern Electric Power Co [Member] | SWEPCo's Guarantee Of Debt [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract] | ||||||||
As Reported on the Consolidated Balance Sheet | 0 | 0 | 0 | |||||
Maximum Exposure | 44,897,000 | 44,897,000 | 49,564,000 | |||||
Southwestern Electric Power Co [Member] | Current Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 64,737,000 | 64,737,000 | 56,535,000 | |||||
Southwestern Electric Power Co [Member] | Net Property Plant And Equipment [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 160,575,000 | 160,575,000 | 170,436,000 | |||||
Southwestern Electric Power Co [Member] | Other Non Current Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 55,760,000 | 55,760,000 | 55,076,000 | |||||
Southwestern Electric Power Co [Member] | Total Assets [Member] | Sabine Mining Co [Member] | ||||||||
ASSETS | ||||||||
Assets | 281,072,000 | 281,072,000 | 282,047,000 | |||||
Southwestern Electric Power Co [Member] | Current Liabilities [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 32,005,000 | 32,005,000 | 31,446,000 | |||||
Southwestern Electric Power Co [Member] | Noncurrent Liabilities [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 248,745,000 | 248,745,000 | 250,340,000 | |||||
Southwestern Electric Power Co [Member] | Equity [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | 322,000 | 322,000 | 261,000 | |||||
Southwestern Electric Power Co [Member] | Total Liabilities And Equity [Member] | Sabine Mining Co [Member] | ||||||||
LIABILITIES AND EQUITY | ||||||||
Liabilities and Equity | $281,072,000 | $281,072,000 | $282,047,000 | |||||
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 50.00% | 50.00% | ||||||
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Percentage Interest in Rockport Plant Unit 2 Lease | 50.00% | 50.00% | ||||||
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Jointly Owned Utility Plant, Proportionate Ownership Share | 100.00% | 100.00% | ||||||
Cleco Power, LLC [Member] | Dolet Hills Lignite Co, LLC [Member] | ||||||||
Variable Interest Entities (Textuals) [Abstract] | ||||||||
Percentage of VIE Sales of Lignite Produced | 50.00% | |||||||
[1] | Includes an intercompany item eliminated in consolidation of $84 million. | |||||||
[2] | Includes an intercompany item eliminated in consolidation of $89 million. | |||||||
[3] | Includes an intercompany item eliminated in consolidation of $121 million. |
Sustainable_Cost_Reductions_De
Sustainable Cost Reductions (Details) (USD $) | 9 Months Ended | 12 Months Ended |
In Thousands, unless otherwise specified | Sep. 30, 2013 | Dec. 31, 2012 |
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | $2,000 | $25,000 |
Incurred | 16,000 | |
Settled | -30,000 | |
Adjustments | -9,000 | |
Remaining Balance | 2,000 | 25,000 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | 47,000 | |
Utility Operations [Member] | ||
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs Percentage | 95.00% | |
Appalachian Power Co [Member] | ||
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | 33 | 1,321 |
Expense Allocation from AEPSC | 1,017 | |
Incurred | 0 | |
Settled | -1,575 | |
Adjustments | -730 | |
Remaining Balance | 33 | 1,321 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | 8,472 | |
Indiana Michigan Power Co [Member] | ||
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | 39 | 1,357 |
Expense Allocation from AEPSC | 736 | |
Incurred | 0 | |
Settled | -1,681 | |
Adjustments | -373 | |
Remaining Balance | 39 | 1,357 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | 5,678 | |
Ohio Power Co [Member] | ||
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | 451 | 3,450 |
Expense Allocation from AEPSC | 1,354 | |
Incurred | 6,114 | |
Settled | -8,837 | |
Adjustments | -1,630 | |
Remaining Balance | 451 | 3,450 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | 13,498 | |
Public Service Co Of Oklahoma [Member] | ||
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | 23 | 652 |
Expense Allocation from AEPSC | 325 | |
Incurred | 0 | |
Settled | -483 | |
Adjustments | -471 | |
Remaining Balance | 23 | 652 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | 3,675 | |
Southwestern Electric Power Co [Member] | ||
Sustainable Cost Reductions [Abstract] | ||
Beginning Balance | 34 | 627 |
Expense Allocation from AEPSC | 622 | |
Incurred | 0 | |
Settled | -1,620 | |
Adjustments | 405 | |
Remaining Balance | 34 | 627 |
Sustainable Cost Reductions Text [Abstract] | ||
Severance Costs | $5,709 |