Document_and_Entity_Informatio
Document and Entity Information | 3 Months Ended | |
Mar. 31, 2014 | Apr. 23, 2014 | |
Entity Registrant Name | 'AMERICAN ELECTRIC POWER CO INC | ' |
Entity Central Index Key | '0000004904 | ' |
Document Type | '10-Q | ' |
Document Period End Date | 31-Mar-14 | ' |
Amendment Flag | 'false | ' |
Document Fiscal Year Focus | '2014 | ' |
Document Fiscal Period Focus | 'Q1 | ' |
Current Fiscal Year End Date | '--12-31 | ' |
Entity Filer Category | 'Large Accelerated Filer | ' |
Entity Common Stock, Shares Outstanding | ' | 488,083,018 |
Appalachian Power Co [Member] | ' | ' |
Entity Registrant Name | 'APPALACHIAN POWER CO | ' |
Entity Central Index Key | '0000006879 | ' |
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 | '0000050172 | ' |
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 | '0000073986 | ' |
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 | '0000081027 | ' |
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 | '0000092487 | ' |
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 | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Revenues | ' | ' |
Vertically Integrated Utilities | $2,549,000,000 | $2,356,000,000 |
Transmission and Distribution Utilities | 1,161,000,000 | 1,090,000,000 |
Generation and Marketing | 821,000,000 | 258,000,000 |
Other Revenues | 117,000,000 | 122,000,000 |
TOTAL REVENUES | 4,648,000,000 | 3,826,000,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 1,168,000,000 | 1,031,000,000 |
Purchased Electricity for Resale | 638,000,000 | 371,000,000 |
Other Operation | 780,000,000 | 738,000,000 |
Maintenance | 292,000,000 | 293,000,000 |
Depreciation and Amortization | 491,000,000 | 420,000,000 |
Taxes Other Than Income Taxes | 238,000,000 | 218,000,000 |
TOTAL EXPENSES | 3,607,000,000 | 3,071,000,000 |
OPERATING INCOME (LOSS) | 1,041,000,000 | 755,000,000 |
Other Income (Expense): | ' | ' |
Interest and Investment Income | 1,000,000 | 3,000,000 |
Carrying Costs Income | 6,000,000 | 4,000,000 |
Allowance for Equity Funds Used During Construction | 22,000,000 | 15,000,000 |
Interest Expense | -220,000,000 | -232,000,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 850,000,000 | 545,000,000 |
Income Tax Expense (Credit) | 307,000,000 | 195,000,000 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 18,000,000 | 14,000,000 |
NET INCOME (LOSS) | 561,000,000 | 364,000,000 |
Net Income Attributable to Noncontrolling Interests | 1,000,000 | 1,000,000 |
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS | 560,000,000 | 363,000,000 |
Earnings Per Share | ' | ' |
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING | 487,867,089 | 485,823,668 |
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $1.15 | $0.75 |
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING | 488,271,167 | 486,344,036 |
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS | $1.15 | $0.75 |
CASH DIVIDENDS DECLARED PER SHARE | $0.50 | $0.47 |
Appalachian Power Co [Member] | ' | ' |
Revenues | ' | ' |
Vertically Integrated Utilities | 866,457,000 | 872,732,000 |
Sales to AEP Affiliates | 44,914,000 | 76,860,000 |
Other Revenues | 2,020,000 | 1,902,000 |
TOTAL REVENUES | 913,391,000 | 951,494,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 230,737,000 | 204,939,000 |
Purchased Electricity for Resale | 168,991,000 | 65,456,000 |
Purchased Electricity from AEP Affiliates | 4,662,000 | 222,942,000 |
Other Operation | 93,538,000 | 78,908,000 |
Maintenance | 60,090,000 | 99,386,000 |
Depreciation and Amortization | 104,586,000 | 87,903,000 |
Taxes Other Than Income Taxes | 30,777,000 | 27,400,000 |
TOTAL EXPENSES | 693,381,000 | 786,934,000 |
OPERATING INCOME (LOSS) | 220,010,000 | 164,560,000 |
Other Income (Expense): | ' | ' |
Interest Income | 401,000 | 331,000 |
Carrying Costs Income | -1,875,000 | 103,000 |
Allowance for Equity Funds Used During Construction | 1,235,000 | 770,000 |
Interest Expense | -51,672,000 | -48,204,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 168,099,000 | 117,560,000 |
Income Tax Expense (Credit) | 66,248,000 | 47,012,000 |
NET INCOME (LOSS) | 101,851,000 | 70,548,000 |
Indiana Michigan Power Co [Member] | ' | ' |
Revenues | ' | ' |
Vertically Integrated Utilities | 614,843,000 | 490,603,000 |
Sales to AEP Affiliates | 2,284,000 | 54,977,000 |
Other Revenues - Affiliated | 24,727,000 | 35,825,000 |
Other Revenues | 0 | 1,988,000 |
TOTAL REVENUES | 641,854,000 | 583,393,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 156,643,000 | 104,865,000 |
Purchased Electricity for Resale | 5,362,000 | 41,812,000 |
Purchased Electricity from AEP Affiliates | 72,056,000 | 101,376,000 |
Other Operation | 141,350,000 | 145,238,000 |
Maintenance | 48,565,000 | 45,514,000 |
Depreciation and Amortization | 50,031,000 | 40,902,000 |
Taxes Other Than Income Taxes | 21,823,000 | 22,456,000 |
TOTAL EXPENSES | 495,830,000 | 502,163,000 |
OPERATING INCOME (LOSS) | 146,024,000 | 81,230,000 |
Other Income (Expense): | ' | ' |
Interest Income | 1,049,000 | 2,055,000 |
Allowance for Equity Funds Used During Construction | 3,964,000 | 5,646,000 |
Interest Expense | -25,633,000 | -24,211,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 125,404,000 | 64,720,000 |
Income Tax Expense (Credit) | 38,315,000 | 21,263,000 |
NET INCOME (LOSS) | 87,089,000 | 43,457,000 |
Ohio Power Co [Member] | ' | ' |
Revenues | ' | ' |
Transmission and Distribution Utilities | 846,906,000 | 933,681,000 |
Sales to AEP Affiliates | 31,978,000 | 285,642,000 |
Other Revenues - Affiliated | 0 | 7,840,000 |
Other Revenues | 1,308,000 | 6,627,000 |
TOTAL REVENUES | 880,192,000 | 1,233,790,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 0 | 409,584,000 |
Purchased Electricity for Resale | 79,130,000 | 43,185,000 |
Purchased Electricity from AEP Affiliates | 314,124,000 | 80,381,000 |
Other Operation | 151,426,000 | 184,187,000 |
Maintenance | 34,651,000 | 74,295,000 |
Depreciation and Amortization | 58,699,000 | 92,324,000 |
Amortization of Generation Deferrals | 31,186,000 | 0 |
Taxes Other Than Income Taxes | 95,257,000 | 105,021,000 |
TOTAL EXPENSES | 764,473,000 | 988,977,000 |
OPERATING INCOME (LOSS) | 115,719,000 | 244,813,000 |
Other Income (Expense): | ' | ' |
Interest Income | 3,274,000 | 363,000 |
Carrying Costs Income | 7,114,000 | 3,263,000 |
Allowance for Equity Funds Used During Construction | 1,726,000 | 1,304,000 |
Interest Expense | -33,007,000 | -50,173,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 94,826,000 | 199,570,000 |
Income Tax Expense (Credit) | 34,052,000 | 69,796,000 |
NET INCOME (LOSS) | 60,774,000 | 129,774,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Revenues | ' | ' |
Vertically Integrated Utilities | 296,710,000 | 259,903,000 |
Sales to AEP Affiliates | 4,597,000 | 1,834,000 |
Other Revenues | 78,000 | 552,000 |
TOTAL REVENUES | 301,385,000 | 262,289,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 65,937,000 | 43,310,000 |
Purchased Electricity for Resale | 79,691,000 | 64,655,000 |
Purchased Electricity from AEP Affiliates | 11,024,000 | 10,216,000 |
Other Operation | 58,711,000 | 47,807,000 |
Maintenance | 24,745,000 | 28,572,000 |
Depreciation and Amortization | 23,982,000 | 24,180,000 |
Taxes Other Than Income Taxes | 11,969,000 | 9,997,000 |
TOTAL EXPENSES | 276,059,000 | 228,737,000 |
OPERATING INCOME (LOSS) | 25,326,000 | 33,552,000 |
Other Income (Expense): | ' | ' |
Allowance for Equity Funds Used During Construction | 1,431,000 | 980,000 |
Other Income | 1,428,000 | 2,115,000 |
Interest Expense | -13,317,000 | -13,340,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 13,437,000 | 22,327,000 |
Income Tax Expense (Credit) | 4,989,000 | 8,634,000 |
NET INCOME (LOSS) | 8,448,000 | 13,693,000 |
Southwestern Electric Power Co [Member] | ' | ' |
Revenues | ' | ' |
Vertically Integrated Utilities | 426,627,000 | 381,277,000 |
Sales to AEP Affiliates | 13,598,000 | 12,709,000 |
Other Revenues | 365,000 | 331,000 |
TOTAL REVENUES | 440,590,000 | 394,317,000 |
Expenses | ' | ' |
Fuel and Other Consumables Used for Electric Generation | 145,587,000 | 151,358,000 |
Purchased Electricity for Resale | 61,165,000 | 39,760,000 |
Purchased Electricity from AEP Affiliates | 3,766,000 | 1,017,000 |
Other Operation | 68,537,000 | 59,448,000 |
Maintenance | 30,411,000 | 27,791,000 |
Depreciation and Amortization | 45,661,000 | 44,882,000 |
Taxes Other Than Income Taxes | 20,737,000 | 19,422,000 |
TOTAL EXPENSES | 375,864,000 | 343,678,000 |
OPERATING INCOME (LOSS) | 64,726,000 | 50,639,000 |
Other Income (Expense): | ' | ' |
Allowance for Equity Funds Used During Construction | 2,081,000 | 1,024,000 |
Other Income | 1,967,000 | 1,054,000 |
Interest Expense | -31,876,000 | -33,990,000 |
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 34,817,000 | 17,703,000 |
Income Tax Expense (Credit) | 12,165,000 | 6,796,000 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 310,000 | 641,000 |
NET INCOME (LOSS) | 22,962,000 | 11,548,000 |
Net Income Attributable to Noncontrolling Interests | 1,102,000 | 1,090,000 |
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS | $21,860,000 | $10,458,000 |
Consolidated_Statements_of_Com
Consolidated Statements of Comprehensive Income (Loss) (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Net Income (Loss) | $561,000,000 | $364,000,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | 5,000,000 | 24,000,000 |
Securities Available for Sale, Net of Tax | 0 | 1,000,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 1,000,000 | 6,000,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 6,000,000 | 31,000,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 567,000,000 | 395,000,000 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,000,000 | 1,000,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | 566,000,000 | 394,000,000 |
Appalachian Power Co [Member] | ' | ' |
Net Income (Loss) | 101,851,000 | 70,548,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | 246,000 | 1,258,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | -333,000 | 358,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | -87,000 | 1,616,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 101,764,000 | 72,164,000 |
Indiana Michigan Power Co [Member] | ' | ' |
Net Income (Loss) | 87,089,000 | 43,457,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | 425,000 | 3,123,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 43,000 | 176,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 468,000 | 3,299,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 87,557,000 | 46,756,000 |
Ohio Power Co [Member] | ' | ' |
Net Income (Loss) | 60,774,000 | 129,774,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | -448,000 | 1,066,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 0 | 3,269,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | -448,000 | 4,335,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 60,326,000 | 134,109,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Net Income (Loss) | 8,448,000 | 13,693,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | -246,000 | -167,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | -246,000 | -167,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 8,202,000 | 13,526,000 |
Southwestern Electric Power Co [Member] | ' | ' |
Net Income (Loss) | 22,962,000 | 11,548,000 |
OTHER COMPREHENSIVE INCOME | ' | ' |
Cash Flow Hedges, Net of Tax | 502,000 | 596,000 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | -234,000 | -63,000 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 268,000 | 533,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 23,230,000 | 12,081,000 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1,102,000 | 1,090,000 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $22,128,000 | $10,991,000 |
Consolidated_Statements_of_Com1
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Cash Flow Hedges, Tax | $3,000,000 | $13,000,000 |
Securities Available for Sale, Tax | 0 | 1,000,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 0 | 3,000,000 |
Appalachian Power Co [Member] | ' | ' |
Cash Flow Hedges, Tax | 132,000 | 677,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | -179,000 | 193,000 |
Indiana Michigan Power Co [Member] | ' | ' |
Cash Flow Hedges, Tax | 229,000 | 1,682,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 23,000 | 94,000 |
Ohio Power Co [Member] | ' | ' |
Cash Flow Hedges, Tax | -241,000 | 574,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | 0 | 1,760,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Cash Flow Hedges, Tax | -132,000 | -90,000 |
Southwestern Electric Power Co [Member] | ' | ' |
Cash Flow Hedges, Tax | 270,000 | 321,000 |
Amortization of Pension and OPEB Deferred Costs, Tax | ($126,000) | ($34,000) |
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, 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 | ' | ' | ' | ' | ' | ' | 506,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of Common Stock, Value | 15,000,000 | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of Common Stock, Shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock Dividends | ' | -50,000,000 | -12,500,000 | -75,000,000 | -13,750,000 | 31,250,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -50,000,000 | -12,500,000 | -75,000,000 | -13,750,000 | 31,250,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock Dividends | -230,000,000 | ' | ' | ' | ' | -964,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -229,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | -964,000 |
Other Changes in Equity | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 363,000,000 | ' | ' | ' | ' | 10,458,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Net Income (Loss) Attributable to Noncontrolling Interests | 1,000,000 | ' | ' | ' | ' | 1,090,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 1,090,000 |
Net Income (Loss) | 364,000,000 | 70,548,000 | 43,457,000 | 129,774,000 | 13,693,000 | 11,548,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 70,548,000 | 43,457,000 | 129,774,000 | 13,693,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss) | 31,000,000 | 1,616,000 | 3,299,000 | 4,335,000 | -167,000 | 533,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 31,000,000 | 1,616,000 | 3,299,000 | 4,335,000 | -167,000 | 533,000 | ' | ' |
Ending Balance at Mar. 31, 2013 | 15,421,000,000 | 3,074,726,000 | 1,838,031,000 | 4,584,818,000 | 916,054,000 | 2,001,340,000 | 3,291,000,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 6,066,000,000 | 1,573,752,000 | 980,896,000 | 1,744,099,000 | 364,037,000 | 674,606,000 | 6,370,000,000 | 1,268,798,000 | 826,135,000 | 2,680,908,000 | 388,473,000 | 1,208,014,000 | -306,000,000 | -28,282,000 | -25,584,000 | -161,390,000 | 6,314,000 | -17,327,000 | 0 | 387,000 |
Ending Balance, Shares at Mar. 31, 2013 | ' | ' | ' | ' | ' | ' | 506,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Beginning Balance at Dec. 31, 2013 | 16,086,000,000 | 3,229,432,000 | 1,922,153,000 | 1,625,265,000 | 942,101,000 | 2,055,917,000 | 3,303,000,000 | 260,458,000 | 56,584,000 | 321,201,000 | 157,230,000 | 135,660,000 | 6,131,000,000 | 1,809,562,000 | 980,896,000 | 663,782,000 | 364,037,000 | 674,606,000 | 6,766,000,000 | 1,156,461,000 | 900,182,000 | 633,203,000 | 415,076,000 | 1,253,617,000 | -115,000,000 | 2,951,000 | -15,509,000 | 7,079,000 | 5,758,000 | -8,444,000 | 1,000,000 | 478,000 |
Beginning Balance, Shares at Dec. 31, 2013 | 508,113,964 | ' | ' | ' | 10,482,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of Common Stock, Value | 15,000,000 | ' | ' | ' | ' | ' | 2,000,000 | ' | ' | ' | ' | ' | 13,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Issuance of Common Stock, Shares | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock Dividends | ' | -20,000,000 | -25,000,000 | -25,000,000 | ' | -25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -20,000,000 | -25,000,000 | -25,000,000 | ' | -25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Common Stock Dividends | -245,000,000 | ' | ' | ' | ' | -1,236,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -244,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -1,000,000 | -1,236,000 |
Other Changes in Equity | -4,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | -6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,000,000 | ' |
Net Income (Loss) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 560,000,000 | ' | ' | ' | ' | 21,860,000 | ' | ' | ' | ' | ' | ' | ' | ' |
Net Income (Loss) Attributable to Noncontrolling Interests | 1,000,000 | ' | ' | ' | ' | 1,102,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,000,000 | 1,102,000 |
Net Income (Loss) | 561,000,000 | 101,851,000 | 87,089,000 | 60,774,000 | 8,448,000 | 22,962,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 101,851,000 | 87,089,000 | 60,774,000 | 8,448,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other Comprehensive Income (Loss) | 6,000,000 | -87,000 | 468,000 | -448,000 | -246,000 | 268,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | -87,000 | 468,000 | -448,000 | -246,000 | 268,000 | ' | ' |
Ending Balance at Mar. 31, 2014 | $16,419,000,000 | $3,311,196,000 | $1,984,710,000 | $1,660,591,000 | $950,303,000 | $2,052,911,000 | $3,305,000,000 | $260,458,000 | $56,584,000 | $321,201,000 | $157,230,000 | $135,660,000 | $6,144,000,000 | $1,809,562,000 | $980,896,000 | $663,782,000 | $364,037,000 | $674,606,000 | $7,076,000,000 | $1,238,312,000 | $962,271,000 | $668,977,000 | $423,524,000 | $1,250,477,000 | ($109,000,000) | $2,864,000 | ($15,041,000) | $6,631,000 | $5,512,000 | ($8,176,000) | $3,000,000 | $344,000 |
Ending Balance, Shares at Mar. 31, 2014 | 508,397,086 | ' | ' | ' | 10,482,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Condensed_Consolidated_Balance
Condensed Consolidated Balance Sheets (USD $) | Mar. 31, 2014 | Dec. 31, 2013 | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | $292,000,000 | $118,000,000 | ||
Other Temporary Investments | 310,000,000 | 353,000,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 785,000,000 | 746,000,000 | ||
Accrued Unbilled Revenues | 143,000,000 | 157,000,000 | ||
Pledged Accounts Receivable - AEP Credit | 1,015,000,000 | 945,000,000 | ||
Miscellaneous | 66,000,000 | 72,000,000 | ||
Allowance for Uncollectible Accounts | -66,000,000 | -60,000,000 | ||
Total Accounts Receivable | 1,943,000,000 | 1,860,000,000 | ||
Fuel | 490,000,000 | 701,000,000 | ||
Materials and Supplies | 724,000,000 | 722,000,000 | ||
Risk Management Assets | 125,000,000 | 160,000,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 175,000,000 | 80,000,000 | ||
Margin Deposits | 117,000,000 | 70,000,000 | ||
Prepayments and Other Current Assets | 159,000,000 | 246,000,000 | ||
TOTAL CURRENT ASSETS | 4,335,000,000 | 4,310,000,000 | ||
Property, Plant and Equipment | ' | ' | ||
Generation | 25,174,000,000 | 25,074,000,000 | ||
Transmission | 11,014,000,000 | 10,893,000,000 | ||
Distribution | 16,518,000,000 | 16,377,000,000 | ||
Other Property, Plant and Equipment | 5,552,000,000 | 5,470,000,000 | ||
Construction Work in Progress | 2,836,000,000 | 2,471,000,000 | ||
Total Property, Plant and Equipment | 61,094,000,000 | 60,285,000,000 | ||
Accumulated Depreciation and Amortization | 19,564,000,000 | 19,288,000,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 41,530,000,000 | 40,997,000,000 | ||
Other Noncurrent Assets | ' | ' | ||
Regulatory Assets | 4,384,000,000 | 4,376,000,000 | ||
Securitized Assets | 2,308,000,000 | 2,373,000,000 | ||
Spent Nuclear Fuel and Decommissioning Trusts | 1,962,000,000 | 1,932,000,000 | ||
Goodwill | 91,000,000 | 91,000,000 | ||
Long-term Risk Management Assets | 266,000,000 | 297,000,000 | ||
Deferred Charges and Other Noncurrent Assets | 2,162,000,000 | 2,038,000,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 11,173,000,000 | 11,107,000,000 | ||
TOTAL ASSETS | 57,038,000,000 | 56,414,000,000 | ||
Current Liabilities | ' | ' | ||
Accounts Payable | 1,213,000,000 | 1,266,000,000 | ||
Short-term Debt: | ' | ' | ||
Securitized Debt for Receivable - AEP Credit | 700,000,000 | [1] | 700,000,000 | [1] |
Other Short-term Debt | 632,000,000 | 57,000,000 | ||
Total Short-term Debt | 1,332,000,000 | 757,000,000 | ||
Long-term Debt Due Within One Year | 1,612,000,000 | 1,549,000,000 | ||
Risk Management Liabilities | 60,000,000 | 90,000,000 | ||
Customer Deposits | 302,000,000 | 299,000,000 | ||
Accrued Taxes | 803,000,000 | 822,000,000 | ||
Accrued Interest | 220,000,000 | 245,000,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 60,000,000 | 119,000,000 | ||
Other Current Liabilities | 917,000,000 | 965,000,000 | ||
TOTAL CURRENT LIABILITIES | 6,519,000,000 | 6,112,000,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 16,475,000,000 | 16,828,000,000 | ||
Long-term Risk Management Liabilities | 137,000,000 | 177,000,000 | ||
Deferred Income Taxes | 10,446,000,000 | 10,300,000,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 3,765,000,000 | 3,694,000,000 | ||
Asset Retirement Obligations | 1,853,000,000 | 1,835,000,000 | ||
Employee Benefits and Pension Obligations | 456,000,000 | 415,000,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 968,000,000 | 967,000,000 | ||
TOTAL NONCURRENT LIABILITIES | 34,100,000,000 | 34,216,000,000 | ||
TOTAL LIABILITIES | 40,619,000,000 | 40,328,000,000 | ||
Rate Matters | ' | ' | ||
Commitments and Contingencies | ' | ' | ||
Equity | ' | ' | ||
Common Stock | 3,305,000,000 | 3,303,000,000 | ||
Paid-in Capital | 6,144,000,000 | 6,131,000,000 | ||
Retained Earnings | 7,076,000,000 | 6,766,000,000 | ||
Accumulated Other Comprehensive Income (Loss) | -109,000,000 | -115,000,000 | ||
TOTAL COMMON SHAREHOLDER'S EQUITY | 16,416,000,000 | 16,085,000,000 | ||
Noncontrolling Interests | 3,000,000 | 1,000,000 | ||
TOTAL EQUITY | 16,419,000,000 | 16,086,000,000 | ||
TOTAL LIABILITIES AND EQUITY | 57,038,000,000 | 56,414,000,000 | ||
Appalachian Power Co [Member] | ' | ' | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | 4,758,000 | 2,745,000 | ||
Advances to Affiliates | 245,516,000 | 92,485,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 150,954,000 | 142,010,000 | ||
Affiliated Companies | 72,283,000 | 113,793,000 | ||
Accrued Unbilled Revenues | 46,631,000 | 55,930,000 | ||
Miscellaneous | 472,000 | 412,000 | ||
Allowance for Uncollectible Accounts | -3,517,000 | -2,443,000 | ||
Total Accounts Receivable | 266,823,000 | 309,702,000 | ||
Fuel | 103,983,000 | 191,811,000 | ||
Materials and Supplies | 128,614,000 | 128,843,000 | ||
Risk Management Assets | 15,972,000 | 21,171,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 79,498,000 | 39,811,000 | ||
Prepayments and Other Current Assets | 33,677,000 | 16,472,000 | ||
TOTAL CURRENT ASSETS | 878,841,000 | 803,040,000 | ||
Property, Plant and Equipment | ' | ' | ||
Generation | 6,752,422,000 | 6,745,172,000 | ||
Transmission | 2,173,839,000 | 2,160,660,000 | ||
Distribution | 3,161,917,000 | 3,139,150,000 | ||
Other Property, Plant and Equipment | 365,750,000 | 357,517,000 | ||
Construction Work in Progress | 217,713,000 | 184,701,000 | ||
Total Property, Plant and Equipment | 12,671,641,000 | 12,587,200,000 | ||
Accumulated Depreciation and Amortization | 3,679,394,000 | 3,617,990,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 8,992,247,000 | 8,969,210,000 | ||
Other Noncurrent Assets | ' | ' | ||
Regulatory Assets | 1,006,426,000 | 1,003,890,000 | ||
Securitized Assets | 364,984,000 | 369,355,000 | ||
Long-term Risk Management Assets | 14,013,000 | 16,948,000 | ||
Deferred Charges and Other Noncurrent Assets | 157,592,000 | 148,205,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 1,543,015,000 | 1,538,398,000 | ||
TOTAL ASSETS | 11,414,103,000 | 11,310,648,000 | ||
Current Liabilities | ' | ' | ||
Accounts Payable | 188,773,000 | 169,184,000 | ||
Affiliated Companies | 87,447,000 | 120,789,000 | ||
Short-term Debt: | ' | ' | ||
Long-term Debt Due Within One Year | 553,399,000 | 342,360,000 | ||
Risk Management Liabilities | 4,636,000 | 8,892,000 | ||
Customer Deposits | 69,180,000 | 66,040,000 | ||
Deferred Income Taxes | 12,208,000 | 6,899,000 | ||
Accrued Taxes | 115,557,000 | 114,699,000 | ||
Accrued Interest | 62,397,000 | 51,899,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 45,144,000 | 107,048,000 | ||
Other Current Liabilities | 76,445,000 | 97,566,000 | ||
TOTAL CURRENT LIABILITIES | 1,215,186,000 | 1,085,376,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 3,555,117,000 | 3,765,997,000 | ||
Long-term Debt - Affiliated | 86,000,000 | 86,000,000 | ||
Long-term Risk Management Liabilities | 7,929,000 | 10,241,000 | ||
Deferred Income Taxes | 2,297,662,000 | 2,232,441,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 648,895,000 | 631,225,000 | ||
Employee Benefits and Pension Obligations | 105,927,000 | 82,264,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 186,191,000 | 187,672,000 | ||
TOTAL NONCURRENT LIABILITIES | 6,887,721,000 | 6,995,840,000 | ||
TOTAL LIABILITIES | 8,102,907,000 | 8,081,216,000 | ||
Rate Matters | ' | ' | ||
Commitments and Contingencies | ' | ' | ||
Equity | ' | ' | ||
Common Stock | 260,458,000 | 260,458,000 | ||
Paid-in Capital | 1,809,562,000 | 1,809,562,000 | ||
Retained Earnings | 1,238,312,000 | 1,156,461,000 | ||
Accumulated Other Comprehensive Income (Loss) | 2,864,000 | 2,951,000 | ||
TOTAL EQUITY | 3,311,196,000 | 3,229,432,000 | ||
TOTAL LIABILITIES AND EQUITY | 11,414,103,000 | 11,310,648,000 | ||
Indiana Michigan Power Co [Member] | ' | ' | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | 2,288,000 | 1,317,000 | ||
Advances to Affiliates | 59,162,000 | 55,863,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 52,471,000 | 63,011,000 | ||
Affiliated Companies | 71,359,000 | 78,282,000 | ||
Accrued Unbilled Revenues | 13,999,000 | 17,293,000 | ||
Miscellaneous | 1,259,000 | 5,064,000 | ||
Allowance for Uncollectible Accounts | -33,000 | -184,000 | ||
Total Accounts Receivable | 139,055,000 | 163,466,000 | ||
Fuel | 49,365,000 | 53,807,000 | ||
Materials and Supplies | 206,820,000 | 209,718,000 | ||
Risk Management Assets | 12,558,000 | 15,388,000 | ||
Accrued Tax Benefits | 29,792,000 | 48,832,000 | ||
Prepayments and Other Current Assets | 27,897,000 | 38,103,000 | ||
TOTAL CURRENT ASSETS | 526,937,000 | 586,494,000 | ||
Property, Plant and Equipment | ' | ' | ||
Generation | 3,583,883,000 | 3,577,906,000 | ||
Transmission | 1,310,169,000 | 1,304,225,000 | ||
Distribution | 1,641,866,000 | 1,625,057,000 | ||
Other Property, Plant and Equipment | 1,440,408,000 | 1,421,361,000 | ||
Construction Work in Progress | 476,734,000 | 427,164,000 | ||
Total Property, Plant and Equipment | 8,453,060,000 | 8,355,713,000 | ||
Accumulated Depreciation and Amortization | 3,337,401,000 | 3,299,349,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,115,659,000 | 5,056,364,000 | ||
Other Noncurrent Assets | ' | ' | ||
Regulatory Assets | 505,750,000 | 524,114,000 | ||
Spent Nuclear Fuel and Decommissioning Trusts | 1,962,151,000 | 1,931,610,000 | ||
Long-term Risk Management Assets | 9,505,000 | 11,495,000 | ||
Deferred Charges and Other Noncurrent Assets | 140,198,000 | 143,657,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 2,617,604,000 | 2,610,876,000 | ||
TOTAL ASSETS | 8,260,200,000 | 8,253,734,000 | ||
Current Liabilities | ' | ' | ||
Accounts Payable | 121,516,000 | 142,219,000 | ||
Affiliated Companies | 69,635,000 | 93,773,000 | ||
Short-term Debt: | ' | ' | ||
Long-term Debt Due Within One Year | 287,598,000 | 294,845,000 | ||
Risk Management Liabilities | 4,134,000 | 7,029,000 | ||
Customer Deposits | 31,851,000 | 31,103,000 | ||
Accrued Taxes | 83,314,000 | 73,292,000 | ||
Accrued Interest | 15,182,000 | 27,686,000 | ||
Obligations Under Capital Leases | 48,407,000 | 46,210,000 | ||
Other Current Liabilities | 146,801,000 | 139,088,000 | ||
TOTAL CURRENT LIABILITIES | 808,438,000 | 855,245,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 1,725,246,000 | 1,744,171,000 | ||
Long-term Risk Management Liabilities | 5,378,000 | 6,946,000 | ||
Deferred Income Taxes | 1,184,213,000 | 1,183,350,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 1,122,812,000 | 1,112,645,000 | ||
Asset Retirement Obligations | 1,269,671,000 | 1,255,184,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 159,732,000 | 174,040,000 | ||
TOTAL NONCURRENT LIABILITIES | 5,467,052,000 | 5,476,336,000 | ||
TOTAL LIABILITIES | 6,275,490,000 | 6,331,581,000 | ||
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 | 962,271,000 | 900,182,000 | ||
Accumulated Other Comprehensive Income (Loss) | -15,041,000 | -15,509,000 | ||
TOTAL EQUITY | 1,984,710,000 | 1,922,153,000 | ||
TOTAL LIABILITIES AND EQUITY | 8,260,200,000 | 8,253,734,000 | ||
Ohio Power Co [Member] | ' | ' | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | 4,780,000 | 3,004,000 | ||
Restricted Cash for Securitized Funding | 32,054,000 | 19,387,000 | ||
Advances to Affiliates | 0 | 339,070,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 96,218,000 | 67,054,000 | ||
Affiliated Companies | 72,311,000 | 74,771,000 | ||
Accrued Unbilled Revenues | 49,761,000 | 36,353,000 | ||
Miscellaneous | 747,000 | 1,559,000 | ||
Allowance for Uncollectible Accounts | -39,602,000 | -34,984,000 | ||
Total Accounts Receivable | 179,435,000 | 144,753,000 | ||
Notes Receivable Due Within One Year - Affiliated | 178,580,000 | 178,580,000 | ||
Materials and Supplies | 55,311,000 | 53,711,000 | ||
Risk Management Assets | 3,980,000 | 3,082,000 | ||
Deferred Income Tax Benefits | 33,642,000 | 36,105,000 | ||
Accrued Tax Benefits | 487,000 | 7,109,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 26,153,000 | 15,829,000 | ||
Prepayments and Other Current Assets | 7,085,000 | 6,483,000 | ||
TOTAL CURRENT ASSETS | 521,507,000 | 807,113,000 | ||
Property, Plant and Equipment | ' | ' | ||
Transmission | 2,030,881,000 | 2,011,289,000 | ||
Distribution | 3,907,852,000 | 3,877,532,000 | ||
Other Property, Plant and Equipment | 379,780,000 | 364,573,000 | ||
Construction Work in Progress | 188,636,000 | 185,428,000 | ||
Total Property, Plant and Equipment | 6,507,149,000 | 6,438,822,000 | ||
Accumulated Depreciation and Amortization | 1,986,318,000 | 1,973,042,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 4,520,831,000 | 4,465,780,000 | ||
Other Noncurrent Assets | ' | ' | ||
Notes Receivable - Affiliated | 118,245,000 | 118,245,000 | ||
Regulatory Assets | 1,398,055,000 | 1,378,697,000 | ||
Securitized Assets | 126,597,000 | 131,582,000 | ||
Deferred Charges and Other Noncurrent Assets | 211,819,000 | 260,141,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 1,854,716,000 | 1,888,665,000 | ||
TOTAL ASSETS | 6,897,054,000 | 7,161,558,000 | ||
Current Liabilities | ' | ' | ||
Advances from Affiliates | 27,108,000 | 0 | ||
Accounts Payable | 128,333,000 | 146,307,000 | ||
Affiliated Companies | 195,954,000 | 222,889,000 | ||
Short-term Debt: | ' | ' | ||
Long-term Debt Due Within One Year | 235,785,000 | 438,595,000 | ||
Accrued Taxes | 324,491,000 | 429,260,000 | ||
Accrued Interest | 49,854,000 | 40,853,000 | ||
Other Current Liabilities | 128,143,000 | 144,334,000 | ||
TOTAL CURRENT LIABILITIES | 1,089,668,000 | 1,422,238,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 2,274,500,000 | 2,296,580,000 | ||
Deferred Income Taxes | 1,352,301,000 | 1,330,711,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 467,433,000 | 435,499,000 | ||
Employee Benefits and Pension Obligations | 28,789,000 | 28,329,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 23,772,000 | 22,936,000 | ||
TOTAL NONCURRENT LIABILITIES | 4,146,795,000 | 4,114,055,000 | ||
TOTAL LIABILITIES | 5,236,463,000 | 5,536,293,000 | ||
Rate Matters | ' | ' | ||
Commitments and Contingencies | ' | ' | ||
Equity | ' | ' | ||
Common Stock | 321,201,000 | 321,201,000 | ||
Paid-in Capital | 663,782,000 | 663,782,000 | ||
Retained Earnings | 668,977,000 | 633,203,000 | ||
Accumulated Other Comprehensive Income (Loss) | 6,631,000 | 7,079,000 | ||
TOTAL EQUITY | 1,660,591,000 | 1,625,265,000 | ||
TOTAL LIABILITIES AND EQUITY | 6,897,054,000 | 7,161,558,000 | ||
Public Service Co Of Oklahoma [Member] | ' | ' | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | 1,756,000 | 1,277,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 29,384,000 | 32,314,000 | ||
Affiliated Companies | 18,634,000 | 30,392,000 | ||
Miscellaneous | 3,460,000 | 3,102,000 | ||
Allowance for Uncollectible Accounts | -325,000 | -462,000 | ||
Total Accounts Receivable | 51,153,000 | 65,346,000 | ||
Fuel | 15,054,000 | 15,191,000 | ||
Materials and Supplies | 52,695,000 | 52,707,000 | ||
Risk Management Assets | 1,349,000 | 1,167,000 | ||
Deferred Income Tax Benefits | 0 | 7,333,000 | ||
Accrued Tax Benefits | 35,708,000 | 21,665,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 26,692,000 | 3,298,000 | ||
Prepayments and Other Current Assets | 5,994,000 | 6,194,000 | ||
TOTAL CURRENT ASSETS | 190,401,000 | 174,178,000 | ||
Property, Plant and Equipment | ' | ' | ||
Generation | 1,236,105,000 | 1,203,221,000 | ||
Transmission | 727,512,000 | 731,312,000 | ||
Distribution | 2,001,049,000 | 1,986,032,000 | ||
Other Property, Plant and Equipment | 411,700,000 | 393,026,000 | ||
Construction Work in Progress | 172,949,000 | 175,890,000 | ||
Total Property, Plant and Equipment | 4,549,315,000 | 4,489,481,000 | ||
Accumulated Depreciation and Amortization | 1,334,507,000 | 1,323,522,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 3,214,808,000 | 3,165,959,000 | ||
Other Noncurrent Assets | ' | ' | ||
Regulatory Assets | 164,929,000 | 156,690,000 | ||
Employee Benefits and Pension Assets | 23,162,000 | 22,629,000 | ||
Deferred Charges and Other Noncurrent Assets | 38,197,000 | 7,238,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 226,288,000 | 186,557,000 | ||
TOTAL ASSETS | 3,631,497,000 | 3,526,694,000 | ||
Current Liabilities | ' | ' | ||
Advances from Affiliates | 70,119,000 | 36,772,000 | ||
Accounts Payable | 106,312,000 | 150,184,000 | ||
Affiliated Companies | 45,468,000 | 45,427,000 | ||
Short-term Debt: | ' | ' | ||
Long-term Debt Due Within One Year | 34,118,000 | 34,115,000 | ||
Risk Management Liabilities | 83,000 | 85,000 | ||
Customer Deposits | 45,676,000 | 45,379,000 | ||
Accrued Taxes | 44,847,000 | 23,442,000 | ||
Accrued Interest | 15,040,000 | 12,646,000 | ||
Other Current Liabilities | 80,931,000 | 58,992,000 | ||
TOTAL CURRENT LIABILITIES | 442,594,000 | 407,042,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 1,015,675,000 | 965,695,000 | ||
Deferred Income Taxes | 848,101,000 | 836,556,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 328,224,000 | 327,673,000 | ||
Employee Benefits and Pension Obligations | 9,966,000 | 10,561,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 36,634,000 | 37,066,000 | ||
TOTAL NONCURRENT LIABILITIES | 2,238,600,000 | 2,177,551,000 | ||
TOTAL LIABILITIES | 2,681,194,000 | 2,584,593,000 | ||
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 | 423,524,000 | 415,076,000 | ||
Accumulated Other Comprehensive Income (Loss) | 5,512,000 | 5,758,000 | ||
TOTAL EQUITY | 950,303,000 | 942,101,000 | ||
TOTAL LIABILITIES AND EQUITY | 3,631,497,000 | 3,526,694,000 | ||
Southwestern Electric Power Co [Member] | ' | ' | ||
Current Assets | ' | ' | ||
Cash and Cash Equivalents | 17,995,000 | 17,241,000 | ||
Accounts Receivable: | ' | ' | ||
Customers | 76,416,000 | 86,263,000 | ||
Affiliated Companies | 21,341,000 | 22,389,000 | ||
Miscellaneous | 24,380,000 | 27,175,000 | ||
Allowance for Uncollectible Accounts | -1,342,000 | -1,418,000 | ||
Total Accounts Receivable | 120,795,000 | 134,409,000 | ||
Fuel | 116,294,000 | 122,026,000 | ||
Materials and Supplies | 75,492,000 | 74,862,000 | ||
Risk Management Assets | 1,907,000 | 1,179,000 | ||
Deferred Income Tax Benefits | 170,410,000 | 177,297,000 | ||
Regulatory Asset for Under-Recovered Fuel Costs | 32,325,000 | 17,949,000 | ||
Prepayments and Other Current Assets | 24,786,000 | 21,089,000 | ||
TOTAL CURRENT ASSETS | 560,004,000 | 566,052,000 | ||
Property, Plant and Equipment | ' | ' | ||
Generation | 3,790,809,000 | 3,764,429,000 | ||
Transmission | 1,190,356,000 | 1,165,167,000 | ||
Distribution | 1,850,573,000 | 1,843,912,000 | ||
Other Property, Plant and Equipment | 873,458,000 | 869,230,000 | ||
Construction Work in Progress | 309,200,000 | 281,849,000 | ||
Total Property, Plant and Equipment | 8,014,396,000 | 7,924,587,000 | ||
Accumulated Depreciation and Amortization | 2,424,701,000 | 2,391,652,000 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,589,695,000 | 5,532,935,000 | ||
Other Noncurrent Assets | ' | ' | ||
Regulatory Assets | 367,406,000 | 369,905,000 | ||
Deferred Charges and Other Noncurrent Assets | 133,123,000 | 92,890,000 | ||
TOTAL OTHER NONCURRENT ASSETS | 500,529,000 | 462,795,000 | ||
TOTAL ASSETS | 6,650,228,000 | 6,561,782,000 | ||
Current Liabilities | ' | ' | ||
Advances from Affiliates | 117,342,000 | 9,180,000 | ||
Accounts Payable | 138,177,000 | 152,653,000 | ||
Affiliated Companies | 53,742,000 | 56,923,000 | ||
Short-term Debt: | ' | ' | ||
Long-term Debt Due Within One Year | 56,750,000 | 3,250,000 | ||
Customer Deposits | 57,065,000 | 56,375,000 | ||
Accrued Taxes | 83,946,000 | 41,508,000 | ||
Accrued Interest | 18,565,000 | 43,996,000 | ||
Obligations Under Capital Leases | 18,220,000 | 17,899,000 | ||
Regulatory Liability for Over-Recovered Fuel Costs | 0 | 7,275,000 | ||
Other Current Liabilities | 61,448,000 | 79,622,000 | ||
TOTAL CURRENT LIABILITIES | 605,255,000 | 468,681,000 | ||
Noncurrent Liabilities | ' | ' | ||
Long-term Debt | 1,985,046,000 | 2,040,082,000 | ||
Deferred Income Taxes | 1,277,745,000 | 1,271,478,000 | ||
Regulatory Liabilities and Deferred Investment Tax Credits | 477,469,000 | 472,128,000 | ||
Asset Retirement Obligations | 88,866,000 | 87,630,000 | ||
Employee Benefits and Pension Obligations | 13,914,000 | 14,602,000 | ||
Obligations Under Capital Leases | 102,984,000 | 105,086,000 | ||
Deferred Credits and Other Noncurrent Liabilities | 46,038,000 | 46,178,000 | ||
TOTAL NONCURRENT LIABILITIES | 3,992,062,000 | 4,037,184,000 | ||
TOTAL LIABILITIES | 4,597,317,000 | 4,505,865,000 | ||
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 | 1,250,477,000 | 1,253,617,000 | ||
Accumulated Other Comprehensive Income (Loss) | -8,176,000 | -8,444,000 | ||
TOTAL COMMON SHAREHOLDER'S EQUITY | 2,052,567,000 | 2,055,439,000 | ||
Noncontrolling Interests | 344,000 | 478,000 | ||
TOTAL EQUITY | 2,052,911,000 | 2,055,917,000 | ||
TOTAL LIABILITIES AND EQUITY | $6,650,228,000 | $6,561,782,000 | ||
[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 $) | Mar. 31, 2014 | Dec. 31, 2013 |
Current Assets | ' | ' |
Cash and Cash Equivalents | $292,000,000 | $118,000,000 |
Other Temporary Investments | 310,000,000 | 353,000,000 |
Fuel | 490,000,000 | 701,000,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 5,552,000,000 | 5,470,000,000 |
Accumulated Depreciation and Amortization | 19,564,000,000 | 19,288,000,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 1,612,000,000 | 1,549,000,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 16,475,000,000 | 16,828,000,000 |
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 | 508,397,086 | 508,113,964 |
Treasury Stock, Shares | 20,336,592 | 20,336,592 |
Appalachian Power Co [Member] | ' | ' |
Current Assets | ' | ' |
Cash and Cash Equivalents | 4,758,000 | 2,745,000 |
Fuel | 103,983,000 | 191,811,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 365,750,000 | 357,517,000 |
Accumulated Depreciation and Amortization | 3,679,394,000 | 3,617,990,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 553,399,000 | 342,360,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 3,555,117,000 | 3,765,997,000 |
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 | 2,288,000 | 1,317,000 |
Fuel | 49,365,000 | 53,807,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 1,440,408,000 | 1,421,361,000 |
Accumulated Depreciation and Amortization | 3,337,401,000 | 3,299,349,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 287,598,000 | 294,845,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 1,725,246,000 | 1,744,171,000 |
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 | 99,439,000 | 107,143,000 |
Ohio Power Co [Member] | ' | ' |
Current Assets | ' | ' |
Cash and Cash Equivalents | 4,780,000 | 3,004,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 379,780,000 | 364,573,000 |
Accumulated Depreciation and Amortization | 1,986,318,000 | 1,973,042,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 235,785,000 | 438,595,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 2,274,500,000 | 2,296,580,000 |
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 |
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 57,137,000 | 34,936,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 210,266,000 | 232,466,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Current Assets | ' | ' |
Cash and Cash Equivalents | 1,756,000 | 1,277,000 |
Fuel | 15,054,000 | 15,191,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 411,700,000 | 393,026,000 |
Accumulated Depreciation and Amortization | 1,334,507,000 | 1,323,522,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 34,118,000 | 34,115,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 1,015,675,000 | 965,695,000 |
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 | 17,995,000 | 17,241,000 |
Fuel | 116,294,000 | 122,026,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 873,458,000 | 869,230,000 |
Accumulated Depreciation and Amortization | 2,424,701,000 | 2,391,652,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 56,750,000 | 3,250,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | 1,985,046,000 | 2,040,082,000 |
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 | 15,539,000 | 15,827,000 |
Fuel | 36,143,000 | 37,518,000 |
Property, Plant and Equipment | ' | ' |
Other Property, Plant and Equipment | 291,571,000 | 291,556,000 |
Accumulated Depreciation and Amortization | 138,789,000 | 134,282,000 |
AEP Subsidiaries [Member] | ' | ' |
Current Assets | ' | ' |
Other Temporary Investments | 293,000,000 | 335,000,000 |
Current Liabilities | ' | ' |
Long-term Debt Due Within One Year | 449,000,000 | 416,000,000 |
Noncurrent Liabilities | ' | ' |
Long-term Debt | $2,388,000,000 | $2,532,000,000 |
Condensed_Consolidated_Stateme1
Condensed Consolidated Statements of Cash Flows (USD $) | 3 Months Ended | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Operating Activities | ' | ' |
Net Income (Loss) | $561,000,000 | $364,000,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 491,000,000 | 420,000,000 |
Deferred Income Taxes | 299,000,000 | 246,000,000 |
Carrying Costs Income | -6,000,000 | -4,000,000 |
Allowance for Equity Funds Used During Construction | -22,000,000 | -15,000,000 |
Mark-to-Market of Risk Management Contracts | 6,000,000 | 34,000,000 |
Amortization of Nuclear Fuel | 38,000,000 | 34,000,000 |
Property Taxes | -54,000,000 | -51,000,000 |
Fuel Over/Under-Recovery, Net | -137,000,000 | -4,000,000 |
Deferral of Ohio Capacity Costs, Net | -56,000,000 | -49,000,000 |
Change in Other Noncurrent Assets | -25,000,000 | 36,000,000 |
Change in Other Noncurrent Liabilities | 77,000,000 | 17,000,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | -83,000,000 | -4,000,000 |
Fuel, Materials and Supplies | 209,000,000 | -1,000,000 |
Accounts Payable | 33,000,000 | -3,000,000 |
Accrued Taxes, Net | -16,000,000 | -69,000,000 |
Other Current Assets | -51,000,000 | -16,000,000 |
Other Current Liabilities | -131,000,000 | -179,000,000 |
Net Cash Flows from (Used for) Operating Activities | 1,133,000,000 | 756,000,000 |
Investing Activities | ' | ' |
Construction Expenditures | -907,000,000 | -843,000,000 |
Change in Other Temporary Investments, Net | 44,000,000 | 75,000,000 |
Purchases of Investment Securities | -165,000,000 | -196,000,000 |
Sales of Investment Securities | 148,000,000 | 168,000,000 |
Acquisitions of Nuclear Fuel | -49,000,000 | -47,000,000 |
Acquisitions of Assets/Businesses | -43,000,000 | -2,000,000 |
Insurance Proceeds Related to Cook Plant Fire | 0 | 72,000,000 |
Other Investing Activities | -9,000,000 | 1,000,000 |
Net Cash Flows from (Used for) Investing Activities | -981,000,000 | -772,000,000 |
Financing Activities | ' | ' |
Issuance of Common Stock, Net | 15,000,000 | 15,000,000 |
Issuance of Long-term Debt | 76,000,000 | 671,000,000 |
Credit Facility Borrowings | 0 | 17,000,000 |
Change in Short-term Debt, Net | 575,000,000 | 329,000,000 |
Retirement of Long-term Debt | -370,000,000 | -858,000,000 |
Credit Facility Repayments | 0 | -20,000,000 |
Principal Payments for Capital Lease Obligations | -33,000,000 | -16,000,000 |
Dividends Paid on Common Stock | -245,000,000 | -230,000,000 |
Other Financing Activities | 4,000,000 | 8,000,000 |
Net Cash Flows from (Used for) Financing Activities | 22,000,000 | -84,000,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 174,000,000 | -100,000,000 |
Cash and Cash Equivalents at Beginning of Period | 118,000,000 | 279,000,000 |
Cash and Cash Equivalents at End of Period | 292,000,000 | 179,000,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 234,000,000 | 253,000,000 |
Net Cash Paid (Received) for Income Taxes | -6,000,000 | -19,000,000 |
Noncash Acquisitions Under Capital Leases | 20,000,000 | 24,000,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | 387,000,000 | 300,000,000 |
Appalachian Power Co [Member] | ' | ' |
Operating Activities | ' | ' |
Net Income (Loss) | 101,851,000 | 70,548,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 104,586,000 | 87,903,000 |
Deferred Income Taxes | 65,690,000 | 17,185,000 |
Carrying Costs Income | 1,875,000 | -103,000 |
Allowance for Equity Funds Used During Construction | -1,235,000 | -770,000 |
Mark-to-Market of Risk Management Contracts | 1,625,000 | 9,404,000 |
Fuel Over/Under-Recovery, Net | -102,051,000 | 20,135,000 |
Change in Other Noncurrent Assets | 4,959,000 | 28,314,000 |
Change in Other Noncurrent Liabilities | 7,799,000 | 5,634,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | 41,382,000 | 7,238,000 |
Fuel, Materials and Supplies | 88,057,000 | -8,726,000 |
Accounts Payable | -4,314,000 | -20,597,000 |
Accrued Taxes, Net | 929,000 | 30,197,000 |
Other Current Assets | -7,276,000 | 642,000 |
Other Current Liabilities | -6,707,000 | -10,917,000 |
Net Cash Flows from (Used for) Operating Activities | 297,170,000 | 236,087,000 |
Investing Activities | ' | ' |
Construction Expenditures | -112,824,000 | -110,552,000 |
Change in Advances to Affiliates, Net | -153,031,000 | -179,000 |
Other Investing Activities | -8,677,000 | -179,000 |
Net Cash Flows from (Used for) Investing Activities | -274,532,000 | -110,910,000 |
Financing Activities | ' | ' |
Issuance of Long-term Debt | -45,000 | -258,000 |
Change in Advances from Affiliates, Net | 0 | -77,314,000 |
Retirement of Long-term Debt | -8,000 | -7,000 |
Principal Payments for Capital Lease Obligations | -1,559,000 | -1,238,000 |
Dividends Paid on Common Stock | -20,000,000 | -50,000,000 |
Other Financing Activities | 987,000 | 1,320,000 |
Net Cash Flows from (Used for) Financing Activities | -20,625,000 | -127,497,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 2,013,000 | -2,320,000 |
Cash and Cash Equivalents at Beginning of Period | 2,745,000 | 3,576,000 |
Cash and Cash Equivalents at End of Period | 4,758,000 | 1,256,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 39,431,000 | 31,018,000 |
Net Cash Paid (Received) for Income Taxes | 0 | 231,000 |
Noncash Acquisitions Under Capital Leases | 2,657,000 | 1,548,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | 38,972,000 | 35,733,000 |
Indiana Michigan Power Co [Member] | ' | ' |
Operating Activities | ' | ' |
Net Income (Loss) | 87,089,000 | 43,457,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 50,031,000 | 40,902,000 |
Deferred Income Taxes | 21,017,000 | 26,791,000 |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expense, Net | 14,821,000 | -5,840,000 |
Allowance for Equity Funds Used During Construction | -3,964,000 | -5,646,000 |
Mark-to-Market of Risk Management Contracts | 426,000 | 9,238,000 |
Amortization of Nuclear Fuel | 38,049,000 | 34,000,000 |
Fuel Over/Under-Recovery, Net | 11,683,000 | 417,000 |
Change in Other Noncurrent Assets | -16,211,000 | -9,217,000 |
Change in Other Noncurrent Liabilities | 11,505,000 | 8,577,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | 24,411,000 | 22,531,000 |
Fuel, Materials and Supplies | 7,340,000 | -6,868,000 |
Accounts Payable | -20,902,000 | -31,801,000 |
Accrued Taxes, Net | 29,583,000 | 14,198,000 |
Other Current Assets | 5,933,000 | 8,487,000 |
Other Current Liabilities | -18,862,000 | -13,443,000 |
Net Cash Flows from (Used for) Operating Activities | 241,949,000 | 135,783,000 |
Investing Activities | ' | ' |
Construction Expenditures | -117,807,000 | -153,262,000 |
Change in Advances to Affiliates, Net | -3,299,000 | -205,008,000 |
Purchases of Investment Securities | -164,511,000 | -184,299,000 |
Sales of Investment Securities | 147,700,000 | 167,670,000 |
Acquisitions of Nuclear Fuel | -49,420,000 | -46,739,000 |
Insurance Proceeds Related to Cook Plant Fire | 0 | 72,000,000 |
Other Investing Activities | 8,860,000 | 3,077,000 |
Net Cash Flows from (Used for) Investing Activities | -178,477,000 | -346,561,000 |
Financing Activities | ' | ' |
Issuance of Long-term Debt | 0 | 247,771,000 |
Retirement of Long-term Debt | -26,337,000 | -24,864,000 |
Principal Payments for Capital Lease Obligations | -11,569,000 | -1,265,000 |
Dividends Paid on Common Stock | -25,000,000 | -12,500,000 |
Other Financing Activities | 405,000 | 646,000 |
Net Cash Flows from (Used for) Financing Activities | -62,501,000 | 209,788,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 971,000 | -990,000 |
Cash and Cash Equivalents at Beginning of Period | 1,317,000 | 1,562,000 |
Cash and Cash Equivalents at End of Period | 2,288,000 | 572,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 34,592,000 | 30,116,000 |
Net Cash Paid (Received) for Income Taxes | 0 | -8,007,000 |
Noncash Acquisitions Under Capital Leases | 2,406,000 | 1,355,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | 56,668,000 | 42,430,000 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31, | 116,000 | 1,485,000 |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 854,000 | 0 |
Ohio Power Co [Member] | ' | ' |
Operating Activities | ' | ' |
Net Income (Loss) | 60,774,000 | 129,774,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 58,699,000 | 92,324,000 |
Amortization of Generation Deferrals | 31,186,000 | 0 |
Deferred Income Taxes | 24,917,000 | 55,328,000 |
Carrying Costs Income | -7,114,000 | -3,263,000 |
Allowance for Equity Funds Used During Construction | -1,726,000 | -1,304,000 |
Mark-to-Market of Risk Management Contracts | -1,060,000 | 12,901,000 |
Property Taxes | 48,743,000 | 55,246,000 |
Fuel Over/Under-Recovery, Net | 12,265,000 | 9,191,000 |
Deferral of Ohio Capacity Costs, Net | -56,167,000 | -49,056,000 |
Change in Other Noncurrent Assets | -21,285,000 | 14,092,000 |
Change in Other Noncurrent Liabilities | 29,277,000 | 1,730,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | -34,984,000 | 58,235,000 |
Fuel, Materials and Supplies | -1,600,000 | -1,388,000 |
Accounts Payable | -30,911,000 | -42,749,000 |
Accrued Taxes, Net | -98,147,000 | -91,308,000 |
Other Current Assets | -1,415,000 | -705,000 |
Other Current Liabilities | -13,633,000 | -21,374,000 |
Net Cash Flows from (Used for) Operating Activities | -2,181,000 | 217,674,000 |
Investing Activities | ' | ' |
Construction Expenditures | -100,220,000 | -131,590,000 |
Change in Restricted Cash for Securitized Funding | -12,668,000 | 0 |
Change in Advances to Affiliates, Net | 339,070,000 | 106,080,000 |
Other Investing Activities | 1,162,000 | 9,760,000 |
Net Cash Flows from (Used for) Investing Activities | 227,344,000 | -15,750,000 |
Financing Activities | ' | ' |
Issuance of Long-term Debt - Affiliated | 0 | 200,000,000 |
Change in Advances from Affiliates, Net | 27,108,000 | 172,211,000 |
Retirement of Long-term Debt | -225,029,000 | -500,000,000 |
Principal Payments for Capital Lease Obligations | -1,396,000 | -2,508,000 |
Dividends Paid on Common Stock | -25,000,000 | -75,000,000 |
Other Financing Activities | 930,000 | 760,000 |
Net Cash Flows from (Used for) Financing Activities | -223,387,000 | -204,537,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 1,776,000 | -2,613,000 |
Cash and Cash Equivalents at Beginning of Period | 3,004,000 | 3,640,000 |
Cash and Cash Equivalents at End of Period | 4,780,000 | 1,027,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 23,425,000 | 50,327,000 |
Net Cash Paid (Received) for Income Taxes | 0 | -2,390,000 |
Noncash Acquisitions Under Capital Leases | 3,324,000 | 1,811,000 |
Government Grants Included in Accounts Receivable as of March 31, | 0 | 1,147,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | 46,910,000 | 69,152,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Operating Activities | ' | ' |
Net Income (Loss) | 8,448,000 | 13,693,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 23,982,000 | 24,180,000 |
Deferred Income Taxes | 19,178,000 | 20,242,000 |
Allowance for Equity Funds Used During Construction | -1,431,000 | -980,000 |
Mark-to-Market of Risk Management Contracts | -267,000 | -3,013,000 |
Property Taxes | -31,260,000 | -28,730,000 |
Fuel Over/Under-Recovery, Net | -23,394,000 | -17,812,000 |
Change In Regulatory Assets | -8,468,000 | 4,165,000 |
Change in Other Noncurrent Assets | -1,045,000 | -3,780,000 |
Change in Other Noncurrent Liabilities | -2,204,000 | 4,620,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | 14,193,000 | 1,665,000 |
Fuel, Materials and Supplies | 149,000 | 1,344,000 |
Accounts Payable | -16,891,000 | -5,827,000 |
Accrued Taxes, Net | 7,362,000 | 6,106,000 |
Other Current Assets | -395,000 | 1,181,000 |
Other Current Liabilities | 22,401,000 | 10,663,000 |
Net Cash Flows from (Used for) Operating Activities | 10,358,000 | 27,717,000 |
Investing Activities | ' | ' |
Construction Expenditures | -93,500,000 | -54,298,000 |
Change in Advances to Affiliates, Net | 0 | 10,558,000 |
Other Investing Activities | 776,000 | 5,196,000 |
Net Cash Flows from (Used for) Investing Activities | -92,724,000 | -38,544,000 |
Financing Activities | ' | ' |
Issuance of Long-term Debt | 49,975,000 | 0 |
Change in Advances from Affiliates, Net | 33,347,000 | 24,004,000 |
Retirement of Long-term Debt | -102,000 | -99,000 |
Principal Payments for Capital Lease Obligations | -941,000 | -754,000 |
Dividends Paid on Common Stock | 0 | -13,750,000 |
Other Financing Activities | 566,000 | 533,000 |
Net Cash Flows from (Used for) Financing Activities | 82,845,000 | 9,934,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 479,000 | -893,000 |
Cash and Cash Equivalents at Beginning of Period | 1,277,000 | 1,367,000 |
Cash and Cash Equivalents at End of Period | 1,756,000 | 474,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 10,487,000 | 10,519,000 |
Net Cash Paid (Received) for Income Taxes | 67,000 | 284,000 |
Noncash Acquisitions Under Capital Leases | 904,000 | 1,015,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | 34,199,000 | 19,868,000 |
Southwestern Electric Power Co [Member] | ' | ' |
Operating Activities | ' | ' |
Net Income (Loss) | 22,962,000 | 11,548,000 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ' | ' |
Depreciation and Amortization | 45,661,000 | 44,882,000 |
Deferred Income Taxes | 11,351,000 | 25,583,000 |
Allowance for Equity Funds Used During Construction | -2,081,000 | -1,024,000 |
Mark-to-Market of Risk Management Contracts | -825,000 | -293,000 |
Property Taxes | -37,511,000 | -36,161,000 |
Fuel Over/Under-Recovery, Net | -21,651,000 | -7,496,000 |
Change in Other Noncurrent Assets | 3,963,000 | -1,245,000 |
Change in Other Noncurrent Liabilities | 2,914,000 | 4,953,000 |
Changes in Certain Components of Working Capital: | ' | ' |
Accounts Receivable, Net | 13,614,000 | 11,654,000 |
Fuel, Materials and Supplies | 5,102,000 | 3,303,000 |
Accounts Payable | -9,410,000 | -12,658,000 |
Customer Deposits | 690,000 | -14,202,000 |
Accrued Taxes, Net | 42,596,000 | 27,994,000 |
Accrued Interest | -25,431,000 | -25,447,000 |
Other Current Assets | -4,663,000 | -638,000 |
Other Current Liabilities | -18,813,000 | -13,551,000 |
Net Cash Flows from (Used for) Operating Activities | 28,468,000 | 17,202,000 |
Investing Activities | ' | ' |
Construction Expenditures | -105,165,000 | -97,786,000 |
Change in Advances to Affiliates, Net | 0 | 126,944,000 |
Other Investing Activities | 1,046,000 | -1,108,000 |
Net Cash Flows from (Used for) Investing Activities | -104,119,000 | 28,050,000 |
Financing Activities | ' | ' |
Credit Facility Borrowings | 0 | 17,091,000 |
Change in Advances from Affiliates, Net | 108,162,000 | 0 |
Retirement of Long-term Debt | -1,625,000 | -1,625,000 |
Credit Facility Repayments | 0 | -19,694,000 |
Principal Payments for Capital Lease Obligations | -4,470,000 | -4,225,000 |
Dividends Paid on Common Stock | -25,000,000 | -31,250,000 |
Dividends Paid on Common Stock | -1,236,000 | -964,000 |
Other Financing Activities | 574,000 | 522,000 |
Net Cash Flows from (Used for) Financing Activities | 76,405,000 | -40,145,000 |
Net Increase (Decrease) in Cash and Cash Equivalents | 754,000 | 5,107,000 |
Cash and Cash Equivalents at Beginning of Period | 17,241,000 | 2,036,000 |
Cash and Cash Equivalents at End of Period | 17,995,000 | 7,143,000 |
Supplementary Information | ' | ' |
Cash Paid for Interest, Net of Capitalized Amounts | 55,123,000 | 55,626,000 |
Net Cash Paid (Received) for Income Taxes | 734,000 | -8,387,000 |
Noncash Acquisitions Under Capital Leases | 2,824,000 | 2,454,000 |
Construction Expenditures Included in Current Liabilities as of March 31, | $53,628,000 | $40,990,000 |
Significant_Accounting_Matters
Significant Accounting Matters | 3 Months Ended | ||||||||||||||
Mar. 31, 2014 | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014. | |||||||||||||||
Revenue Recognition | |||||||||||||||
Electricity Supply and Delivery Activities – Transactions with PJM | |||||||||||||||
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |||||||||||||||
APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |||||||||||||||
AEP's nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales. | |||||||||||||||
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 table presents our basic and diluted EPS calculations included on our condensed statements of income: | |||||||||||||||
Three Months Ended March 31, | |||||||||||||||
2014 | 2013 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 560 | $ | 363 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 487.9 | $ | 1.15 | 485.8 | $ | 0.75 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Restricted Stock Units | 0.4 | - | 0.5 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 488.3 | $ | 1.15 | 486.3 | $ | 0.75 | |||||||||
There were no antidilutive shares outstanding as of March 31, 2014 and 2013. | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |||||||||||||||
Revenue Recognition | |||||||||||||||
Electricity Supply and Delivery Activities – Transactions with PJM | |||||||||||||||
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |||||||||||||||
APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |||||||||||||||
Revenue Recognition | |||||||||||||||
Electricity Supply and Delivery Activities – Transactions with PJM | |||||||||||||||
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |||||||||||||||
APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |||||||||||||||
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. |
New_Accounting_Pronouncements
New Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2014 | |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following summary of a final pronouncement will impact our financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We plan to adopt ASU 2014-08 effective January 1, 2015. | |
Appalachian Power Co [Member] | ' |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015. | |
Indiana Michigan Power Co [Member] | ' |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015. | |
Ohio Power Co [Member] | ' |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015. | |
Public Service Co Of Oklahoma [Member] | ' |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015. | |
Southwestern Electric Power Co [Member] | ' |
New Accounting Pronouncements | ' |
2. NEW ACCOUNTING PRONOUNCEMENT | |
Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements. | |
ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) | |
In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance. | |
The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015. | |
Comprehensive_Income
Comprehensive Income | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Comprehensive Income | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
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, 2013 | $ | - | $ | -23 | $ | 7 | $ | -99 | $ | -115 | |||||||
Change in Fair Value Recognized in AOCI | -14 | - | - | - | -14 | ||||||||||||
Amounts Reclassified from AOCI | 18 | 1 | - | 1 | 20 | ||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 4 | 1 | - | 1 | 6 | ||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 4 | $ | -22 | $ | 7 | $ | -98 | $ | -109 | |||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 18 | 3 | 1 | - | 22 | ||||||||||||
Amounts Reclassified from AOCI | 2 | 1 | - | 6 | 9 | ||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 20 | 4 | 1 | 6 | 31 | ||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 12 | $ | -26 | $ | 5 | $ | -297 | $ | -306 | |||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following table provides details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | ||||||||||||||||
Commodity: | |||||||||||||||||
Vertically Integrated Utilities Revenues | $ | - | $ | - | |||||||||||||
Generation & Marketing Revenues | - | -3 | |||||||||||||||
Purchased Electricity for Resale | 31 | 6 | |||||||||||||||
Property, Plant and Equipment | - | - | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -3 | - | |||||||||||||||
Subtotal - Commodity | 28 | 3 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 2 | 2 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2 | 2 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 30 | 5 | |||||||||||||||
Income Tax (Expense) Credit | 11 | 2 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19 | 3 | |||||||||||||||
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 | - | - | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -5 | -5 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 7 | 14 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2 | 9 | |||||||||||||||
Income Tax (Expense) Credit | 1 | 3 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1 | 6 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 20 | $ | 9 | |||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | |||||||||||||||||
Appalachian Power Co [Member] | ' | ||||||||||||||||
Comprehensive Income | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 94 | $ | 3,090 | $ | -233 | $ | 2,951 | |||||||||
Change in Fair Value Recognized in AOCI | 1,583 | - | - | 1,583 | |||||||||||||
Amounts Reclassified from AOCI | -1,590 | 253 | -333 | -1,670 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -7 | 253 | -333 | -87 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 87 | $ | 3,343 | $ | -566 | $ | 2,864 | |||||||||
APCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 794 | -1 | - | 793 | |||||||||||||
Amounts Reclassified from AOCI | 211 | 254 | 358 | 823 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 1,005 | 253 | 358 | 1,616 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 361 | $ | 2,330 | $ | -30,973 | $ | -28,282 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 20 | |||||||||||||
Purchased Electricity for Resale | -462 | 57 | |||||||||||||||
Other Operation Expense | -10 | -11 | |||||||||||||||
Maintenance Expense | -20 | -16 | |||||||||||||||
Property, Plant and Equipment | -17 | -14 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -1,937 | 289 | |||||||||||||||
Subtotal - Commodity | -2,446 | 325 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 390 | 390 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 390 | 390 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,056 | 715 | |||||||||||||||
Income Tax (Expense) Credit | -719 | 250 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337 | 465 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -1,282 | -1,282 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 770 | 1,833 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -512 | 551 | |||||||||||||||
Income Tax (Expense) Credit | -179 | 193 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333 | 358 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -1,670 | $ | 823 | |||||||||||||
(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 | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 46 | $ | -15,976 | $ | 421 | $ | -15,509 | |||||||||
Change in Fair Value Recognized in AOCI | 1,062 | - | - | 1,062 | |||||||||||||
Amounts Reclassified from AOCI | -1,047 | 410 | 43 | -594 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 15 | 410 | 43 | 468 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 61 | $ | -15,566 | $ | 464 | $ | -15,041 | |||||||||
I&M | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 532 | 2,249 | - | 2,781 | |||||||||||||
Amounts Reclassified from AOCI | 150 | 192 | 176 | 518 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 682 | 2,441 | 176 | 3,299 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 236 | $ | -17,206 | $ | -8,614 | $ | -25,584 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 52 | |||||||||||||
Purchased Electricity for Resale | -717 | 149 | |||||||||||||||
Other Operation Expense | -7 | -7 | |||||||||||||||
Maintenance Expense | -7 | -7 | |||||||||||||||
Property, Plant and Equipment | -10 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -870 | 50 | |||||||||||||||
Subtotal - Commodity | -1,611 | 230 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 631 | 296 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 631 | 296 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -980 | 526 | |||||||||||||||
Income Tax (Expense) Credit | -343 | 184 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637 | 342 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -199 | -199 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 265 | 469 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 66 | 270 | |||||||||||||||
Income Tax (Expense) Credit | 23 | 94 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43 | 176 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -594 | $ | 518 | |||||||||||||
(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 | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 105 | $ | 6,974 | $ | - | $ | 7,079 | |||||||||
Change in Fair Value Recognized in AOCI | - | - | - | - | |||||||||||||
Amounts Reclassified from AOCI | -105 | -343 | - | -448 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -105 | -343 | - | -448 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | 6,631 | $ | - | $ | 6,631 | |||||||||
OPCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | |||||||||
Change in Fair Value Recognized in AOCI | 1,102 | - | - | 1,102 | |||||||||||||
Amounts Reclassified from AOCI | 304 | -340 | 3,269 | 3,233 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 1,406 | -340 | 3,269 | 4,335 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 494 | $ | 7,755 | $ | -169,639 | $ | -161,390 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 134 | |||||||||||||
Purchased Electricity for Resale | - | 382 | |||||||||||||||
Other Operation Expense | -11 | -18 | |||||||||||||||
Maintenance Expense | -11 | -12 | |||||||||||||||
Property, Plant and Equipment | -18 | -19 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -122 | - | |||||||||||||||
Subtotal - Commodity | -162 | 467 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Depreciation and Amortization Expense | -3 | 2 | |||||||||||||||
Interest Expense | -524 | -524 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -527 | -522 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -689 | -55 | |||||||||||||||
Income Tax (Expense) Credit | -241 | -19 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448 | -36 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | - | -1,468 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | - | 6,497 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | 5,029 | |||||||||||||||
Income Tax (Expense) Credit | - | 1,760 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | 3,269 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -448 | $ | 3,233 | |||||||||||||
(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 | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | |||||||||||||||||
Commodity | Foreign Currency | Total | |||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 57 | $ | 5,701 | $ | 5,758 | |||||||||||
Change in Fair Value Recognized in AOCI | - | - | - | ||||||||||||||
Amounts Reclassified from AOCI | -57 | -189 | -246 | ||||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -57 | -189 | -246 | ||||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | 5,512 | $ | 5,512 | |||||||||||
PSO | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 36 | - | 36 | ||||||||||||||
Amounts Reclassified from AOCI | -13 | -190 | -203 | ||||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 23 | -190 | -167 | ||||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 44 | $ | 6,270 | $ | 6,314 | |||||||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Other Operation Expense | $ | -8 | $ | -9 | |||||||||||||
Maintenance Expense | -9 | -4 | |||||||||||||||
Property, Plant and Equipment | -13 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -58 | - | |||||||||||||||
Subtotal - Commodity | -88 | -20 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | -292 | -292 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -292 | -292 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -380 | -312 | |||||||||||||||
Income Tax (Expense) Credit | -134 | -109 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -246 | $ | -203 | |||||||||||||
(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 | ' | ||||||||||||||||
3. COMPREHENSIVE INCOME | |||||||||||||||||
Presentation of Comprehensive Income | |||||||||||||||||
The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 66 | $ | -13,304 | $ | 4,794 | $ | -8,444 | |||||||||
Change in Fair Value Recognized in AOCI | - | - | - | - | |||||||||||||
Amounts Reclassified from AOCI | -66 | 568 | -234 | 268 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -66 | 568 | -234 | 268 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | -12,736 | $ | 4,560 | $ | -8,176 | |||||||||
SWEPCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 44 | - | - | 44 | |||||||||||||
Amounts Reclassified from AOCI | -15 | 567 | -63 | 489 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 29 | 567 | -63 | 533 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 51 | $ | -15,004 | $ | -2,374 | $ | -17,327 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | |||||||||||||||||
The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 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 March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Other Operation Expense | $ | -13 | $ | -10 | |||||||||||||
Maintenance Expense | -10 | -6 | |||||||||||||||
Property, Plant and Equipment | -11 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -67 | - | |||||||||||||||
Subtotal - Commodity | -101 | -23 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 872 | 872 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 872 | 872 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 771 | 849 | |||||||||||||||
Income Tax (Expense) Credit | 269 | 297 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502 | 552 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -478 | -445 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 118 | 348 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -360 | -97 | |||||||||||||||
Income Tax (Expense) Credit | -126 | -34 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234 | -63 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 268 | $ | 489 | |||||||||||||
(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 | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
Rate Matters | ' | |||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in millions) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Storm Related Costs | $ | 21 | $ | 22 | ||||||
Ohio Economic Development Rider | - | 14 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | - | 4 | ||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 104 | 161 | ||||||||
Indiana Under-Recovered Capacity Costs | 28 | 22 | ||||||||
IGCC Pre-Construction Costs | 21 | - | ||||||||
Expanded Net Energy Charge - Coal Inventory | 19 | 21 | ||||||||
Mountaineer Carbon Capture and Storage Product Validation Facility | 13 | 13 | ||||||||
Ormet Special Rate Recovery Mechanism | 10 | 36 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 34 | 37 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 250 | $ | 330 | ||||||
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 Filings | ||||||||||
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 March 31, 2014, OPCo's net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision. | ||||||||||
In August 2012, the PUCO issued an order in a separate proceeding which implemented a 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. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued 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 intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 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. This ruling was generally upheld in rehearing orders in January and March 2013. | ||||||||||
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. | ||||||||||
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo's incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. | ||||||||||
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 November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo's request to implement riders related to the unbundling of the FAC. | ||||||||||
Proposed June 2015 – May 2018 ESP | ||||||||||
In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014. | ||||||||||
If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Significantly Excessive Earnings Test (SEET) Filings | ||||||||||
In January 2011, the PUCO issued an order on the 2009 SEET filing. The 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. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In November 2013, OPCo filed its 2011 SEET filing with the PUCO. OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. | ||||||||||
In November 2013, OPCo filed its 2012 SEET filing with the PUCO. In April 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012 SEET filing is scheduled for April 2014. Management does not believe that there were significantly excessive earnings in 2013 for OPCo. | ||||||||||
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 and associated generation liabilities at net book value to AGR. 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 December 2013, corporate separation of OPCo's generation assets was completed. If any part of the PUCO order is overturned, 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 to recover 2012 incremental storm distribution expenses over twelve months starting with the effective date as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation agreement recommended approval to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. | ||||||||||
2009 Fuel Adjustment Clause Audit | ||||||||||
In January 2012, the PUCO issued an order in OPCo's 2009 FAC 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. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 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. 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 in the PIRR proceeding 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 were held in 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. | ||||||||||
2012 – 2013 Fuel Adjustment Clause Audits | ||||||||||
In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Ormet | ||||||||||
Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), 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 EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo's EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled for May 2014. | ||||||||||
In addition, 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 this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. | ||||||||||
To the extent amounts discussed 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 March 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. | ||||||||||
Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding 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 | ||||||||||
2012 Texas Base Rate Case | ||||||||||
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant's Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo's recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred 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 March 31, 2014, the net book value of Welsh Plant, Unit 2 was $86 million, before cost of removal, including materials and supplies inventory and CWIP. | ||||||||||
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling. This order became final and appealable in April 2014. | ||||||||||
If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Texas Transmission Cost Recovery Factor Filing | ||||||||||
In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice. The ALJ concluded that SWEPCo's application was premature as the PUCT had not completed its ruling on the motions for rehearing of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF calculation would be established. | ||||||||||
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. The rates are subject to refund based on the staff review of the cost of service and the prudency 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. | ||||||||||
2014 Louisiana Formula Rate Filing | ||||||||||
In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
APCo and WPCo Rate Matters | ||||||||||
Plant Transfer | ||||||||||
In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR's one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR. | ||||||||||
APCo IGCC Plant | ||||||||||
As of March 31, 2014, 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. In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Virginia Transmission Rate Adjustment Clause (transmission RAC) | ||||||||||
In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC proceeding in 2015. | ||||||||||
2014 Virginia Biennial Base Rate Case | ||||||||||
In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
PSO Rate Matters | ||||||||||
2014 Oklahoma Base Rate Case | ||||||||||
In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years. | ||||||||||
In April 2014, OCC Staff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, 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% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order. In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base. If any part of the IURC order is overturned by the Indiana Supreme Court, 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 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 March 31, 2014, I&M has incurred costs of $405 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 of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. | ||||||||||
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved 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 depreciation and a return on the net book value of the Tanners Creek Plant 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. | ||||||||||
In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates are expected to result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. A hearing at the MPSC is scheduled for September 2014. | ||||||||||
As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 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 the Tanners Creek Plant and its retirement-related costs, 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. 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. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of March 31, 2014, the net book value of Big Sandy Plant, Unit 2 was $247 million, before cost of removal, including materials and supplies inventory and CWIP. | ||||||||||
In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo's request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income. In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal. A hearing on the motions to dismiss was held in January 2014. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Appalachian Power Co [Member] | ' | |||||||||
Rate Matters | ' | |||||||||
Plant Transfer | ||||||||||
In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR's one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR. | ||||||||||
APCo IGCC Plant | ||||||||||
As of March 31, 2014, 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. In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Virginia Transmission Rate Adjustment Clause (transmission RAC) | ||||||||||
In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC proceeding in 2015. | ||||||||||
2014 Virginia Biennial Base Rate Case | ||||||||||
In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
APCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
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 | $ | 65,206 | ||||||
IGCC Pre-Construction Costs | 20,528 | - | ||||||||
Expanded Net Energy Charge - Coal Inventory | 18,818 | 20,528 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Product Validation Facility | 13,264 | 13,264 | ||||||||
Virginia Demand Response Program Costs | 5,897 | 5,012 | ||||||||
Transmission Agreement Phase-In | 3,450 | 3,313 | ||||||||
Virginia Environmental Rate Adjustment Clause | 1,941 | 2,440 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,287 | 1,287 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 513 | 168 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 130,904 | $ | 111,218 | ||||||
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. 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 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. In June 2013, the WVPSC issued an order consolidating the merger case with APCo's plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The order also directed APCo and WPCo to submit a plan with the WVPSC identifying a course of action to serve the load of WPCo. See the “Plant Transfer” section of APCo Rate Matters. The feasibility of the merger remains under review. | ||||||||||
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% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order. In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base. If any part of the IURC order is overturned by the Indiana Supreme Court, 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 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 March 31, 2014, I&M has incurred costs of $405 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 of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC. | ||||||||||
In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved 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 depreciation and a return on the net book value of the Tanners Creek Plant 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. | ||||||||||
In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates are expected to result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. A hearing at the MPSC is scheduled for September 2014. | ||||||||||
As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 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 the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
I&M | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Indiana Under-Recovered Capacity Costs | $ | 28,149 | $ | 21,945 | ||||||
Cook Plant Turbine | 4,238 | 3,452 | ||||||||
Stranded Costs on Abandoned Plants | 3,897 | 3,896 | ||||||||
Storm Related Costs | 751 | 1,836 | ||||||||
Indiana Deferred Cook Plant Life Cycle Management Project Costs | - | 4,093 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 694 | 164 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 37,729 | $ | 35,386 | ||||||
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Ohio Power Co [Member] | ' | |||||||||
Rate Matters | ' | |||||||||
OPCo Rate Matters | ||||||||||
Ohio Electric Security Plan Filings | ||||||||||
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 March 31, 2014, OPCo's net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision. | ||||||||||
In August 2012, the PUCO issued an order in a separate proceeding which implemented a 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. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued 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 intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 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. This ruling was generally upheld in rehearing orders in January and March 2013. | ||||||||||
In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the 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 OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. | ||||||||||
As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo's incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet. | ||||||||||
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 November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 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. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo's request to implement riders related to the unbundling of the FAC. | ||||||||||
Proposed June 2015 – May 2018 ESP | ||||||||||
In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014. | ||||||||||
If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Significantly Excessive Earnings Test (SEET) Filings | ||||||||||
In January 2011, the PUCO issued an order on the 2009 SEET filing. The 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. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In November 2013, OPCo filed its 2011 SEET filing with the PUCO. OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo. | ||||||||||
In November 2013, OPCo filed its 2012 SEET filing with the PUCO. In April 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012 SEET filing is scheduled for April 2014. Management does not believe that there were significantly excessive earnings in 2013 for OPCo. | ||||||||||
Storm Damage Recovery Rider (SDRR) | ||||||||||
In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting with the effective date as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation agreement recommended approval to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014. | ||||||||||
2009 Fuel Adjustment Clause Audit | ||||||||||
In January 2012, the PUCO issued an order in OPCo's 2009 FAC 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. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 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. 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 in the PIRR proceeding 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 were held in 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. | ||||||||||
2012 – 2013 Fuel Adjustment Clause Audits | ||||||||||
In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Ormet | ||||||||||
Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), 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 EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo's EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled for May 2014. | ||||||||||
In addition, 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 this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement. | ||||||||||
To the extent amounts discussed 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 March 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest. | ||||||||||
Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding 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. | ||||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
OPCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Economic Development Rider | $ | - | $ | 13,854 | ||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Ormet Special Rate Recovery Mechanism | 10,483 | 35,631 | ||||||||
Storm Related Costs | 1,635 | 57,589 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 12,118 | $ | 107,074 | ||||||
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 and associated generation liabilities at net book value to AGR. 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 December 2013, corporate separation of OPCo's generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||
Rate Matters | ' | |||||||||
PSO Rate Matters | ||||||||||
2014 Oklahoma Base Rate Case | ||||||||||
In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years. | ||||||||||
In April 2014, OCC Staff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
PSO | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 19,093 | $ | 18,743 | ||||||
Other Regulatory Assets Not Yet Being Recovered | 1,079 | 845 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 20,172 | $ | 19,588 | ||||||
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 | ||||||||||
2012 Texas Base Rate Case | ||||||||||
In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant's Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo's recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred 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 March 31, 2014, the net book value of Welsh Plant, Unit 2 was $86 million, before cost of removal, including materials and supplies inventory and CWIP. | ||||||||||
Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling. This order became final and appealable in April 2014. | ||||||||||
If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
2013 Texas Transmission Cost Recovery Factor Filing | ||||||||||
In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice. The ALJ concluded that SWEPCo's application was premature as the PUCT had not completed its ruling on the motions for rehearing of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF calculation would be established. | ||||||||||
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. The rates are subject to refund based on the staff review of the cost of service and the prudency 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. | ||||||||||
2014 Louisiana Formula Rate Filing | ||||||||||
In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. | ||||||||||
4. RATE MATTERS | ||||||||||
As discussed in the 2013 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 2013 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 2014 and updates the 2013 Annual Report. | ||||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
SWEPCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Rate Case Expenses | $ | 7,930 | $ | 7,934 | ||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,143 | 1,143 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,025 | 1,951 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 11,098 | $ | 11,028 | ||||||
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 | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
Commitments, Guarantees and Contingencies | ' | |||||||||
5. 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 2013 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 March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $130 million with maturities ranging from June 2014 to April 2015. | ||||||||||
In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of March 31, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75 million with a maturity in July 2014. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility. | ||||||||||
We have $352 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356 million. The letters of credit have maturities ranging from July 2014 to March 2017. | ||||||||||
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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 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. As of March 31, 2014, 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 March 31, 2014, the maximum potential loss for these lease agreements was approximately $21 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 $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014. | ||||||||||
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 | ||||||||||
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 generation 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 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 $8 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. | ||||||||||
OPERATIONAL CONTINGENCIES | ||||||||||
Rockport Plant Litigation | ||||||||||
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District 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. The New York court granted our motion to transfer this case to the U.S. District Court for the Southern District of Ohio. Our motion to dismiss the case, filed in October 2013, is pending. 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. That motion was denied. We are considering seeking a review of this issue by the U.S. Supreme Court. Defendants in these cases, including AEP, previously 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. We are unable to determine a range of potential losses that are reasonably possible of occurring. | ||||||||||
Wage and Hours Lawsuit | ||||||||||
In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. | ||||||||||
In March 2014, the federal court granted plaintiffs' motion to conditionally certify the action as a class action. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring. | ||||||||||
Appalachian Power Co [Member] | ' | |||||||||
Commitments, Guarantees and Contingencies | ' | |||||||||
5. 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 2013 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 $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 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 2016 to March 2017 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
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 March 31, 2014, 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 March 31, 2014, 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 | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Indiana Michigan Power Co [Member] | ' | |||||||||
Commitments, Guarantees and Contingencies | ' | |||||||||
5. 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 2013 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 March 31, 2014, 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-15 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 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 2016 to March 2017 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
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 March 31, 2014, 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 March 31, 2014, 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 | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
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 $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014. | ||||||||||
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 | ||||||||||
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 generation 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 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 $8 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. | ||||||||||
OPERATIONAL CONTINGENCIES | ||||||||||
Rockport Plant Litigation – Affecting I&M | ||||||||||
In July 2013, the Wilmington Trust Company filed a complaint in U.S. District 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. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. The motion to dismiss, filed in October 2013, is pending. 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 | ' | |||||||||
5. 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 2013 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 March 31, 2014, 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-15 | |||||||
OPCo | 3,081 | Jun-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 March 31, 2014, 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 March 31, 2014, 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 | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||
Commitments, Guarantees and Contingencies | ' | |||||||||
5. 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 2013 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 March 31, 2014, 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 March 31, 2014, 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 | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Wage and Hours Lawsuit – Affecting PSO | ||||||||||
In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount. | ||||||||||
In March 2014, the federal court granted plaintiffs' motion to conditionally certify the action as a class action. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. | ||||||||||
Southwestern Electric Power Co [Member] | ' | |||||||||
Commitments, Guarantees and Contingencies | ' | |||||||||
5. 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 2013 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. | ||||||||||
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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 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 March 31, 2014, 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 March 31, 2014, 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 | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
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 $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014. | ||||||||||
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. |
Benefit_Plans
Benefit Plans | 3 Months Ended | |||||||||||
Mar. 31, 2014 | ||||||||||||
Benefit Plans | ' | |||||||||||
6. BENEFIT PLANS | ||||||||||||
Components of Net Periodic Benefit Cost | ||||||||||||
The following table provides the components of our net periodic benefit cost (credit) for the plans for the three months ended March 31, 2014 and 2013: | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 18 | $ | 17 | $ | 4 | $ | 6 | ||||
Interest Cost | 55 | 50 | 17 | 18 | ||||||||
Expected Return on Plan Assets | -66 | -69 | -28 | -27 | ||||||||
Amortization of Prior Service Cost (Credit) | 1 | 1 | -17 | -17 | ||||||||
Amortization of Net Actuarial Loss | 31 | 46 | 5 | 16 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 39 | $ | 45 | $ | -19 | $ | -4 | ||||
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 months ended March 31, 2014 and 2013: | ||||||||||||
APCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,759 | $ | 1,543 | $ | 362 | $ | 641 | ||||
Interest Cost | 7,406 | 6,916 | 3,197 | 3,363 | ||||||||
Expected Return on Plan Assets | -8,482 | -9,260 | -4,633 | -4,536 | ||||||||
Amortization of Prior Service Cost (Credit) | 50 | 49 | -2,513 | -2,512 | ||||||||
Amortization of Net Actuarial Loss | 4,148 | 6,256 | 1,146 | 3,062 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 4,881 | $ | 5,504 | $ | -2,441 | $ | 18 | ||||
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 months ended March 31, 2014 and 2013: | ||||||||||||
I&M | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,517 | $ | 2,184 | $ | 487 | $ | 805 | ||||
Interest Cost | 6,573 | 6,025 | 1,909 | 2,055 | ||||||||
Expected Return on Plan Assets | -7,748 | -8,207 | -3,364 | -3,296 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 49 | -2,355 | -2,355 | ||||||||
Amortization of Net Actuarial Loss | 3,646 | 5,422 | 592 | 1,882 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 5,037 | $ | 5,473 | $ | -2,731 | $ | -909 | ||||
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 months ended March 31, 2014 and 2013: | ||||||||||||
OPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,285 | $ | 2,372 | $ | 256 | $ | 1,300 | ||||
Interest Cost | 5,526 | 10,292 | 1,901 | 4,447 | ||||||||
Expected Return on Plan Assets | -6,607 | -15,141 | -3,380 | -6,238 | ||||||||
Amortization of Prior Service Cost (Credit) | 39 | 71 | -1,731 | -3,231 | ||||||||
Amortization of Net Actuarial Loss | 3,106 | 9,309 | 595 | 4,041 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 3,349 | $ | 6,903 | $ | -2,359 | $ | 319 | ||||
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 months ended March 31, 2014 and 2013: | ||||||||||||
PSO | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,302 | $ | 1,391 | $ | 210 | $ | 343 | ||||
Interest Cost | 3,014 | 2,748 | 893 | 948 | ||||||||
Expected Return on Plan Assets | -3,651 | -3,918 | -1,575 | -1,522 | ||||||||
Amortization of Prior Service Cost (Credit) | 74 | 74 | -1,072 | -1,072 | ||||||||
Amortization of Net Actuarial Loss | 1,688 | 2,461 | 277 | 869 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,427 | $ | 2,756 | $ | -1,267 | $ | -434 | ||||
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 months ended March 31, 2014 and 2013: | ||||||||||||
SWEPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,655 | $ | 1,753 | $ | 253 | $ | 423 | ||||
Interest Cost | 3,163 | 2,864 | 998 | 1,075 | ||||||||
Expected Return on Plan Assets | -3,857 | -4,127 | -1,754 | -1,720 | ||||||||
Amortization of Prior Service Cost (Credit) | 87 | 87 | -1,289 | -1,288 | ||||||||
Amortization of Net Actuarial Loss | 1,761 | 2,553 | 309 | 982 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,809 | $ | 3,130 | $ | -1,483 | $ | -528 |
Business_Segments
Business Segments | 3 Months Ended | |||||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||||
Business Segments | ' | |||||||||||||||||||||||||||
7. BUSINESS SEGMENTS | ||||||||||||||||||||||||||||
Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities 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. | ||||||||||||||||||||||||||||
During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments. In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments. | ||||||||||||||||||||||||||||
Our reportable segments and their related business activities are outlined below: | ||||||||||||||||||||||||||||
Vertically Integrated Utilities | ||||||||||||||||||||||||||||
Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. | ||||||||||||||||||||||||||||
Transmission and Distribution Utilities | ||||||||||||||||||||||||||||
Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC. | ||||||||||||||||||||||||||||
OPCo purchases energy to serve standard service offer customers, and provides capacity for all connected load. | ||||||||||||||||||||||||||||
AEP Transmission Holdco | ||||||||||||||||||||||||||||
Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. | ||||||||||||||||||||||||||||
Generation & Marketing | ||||||||||||||||||||||||||||
Nonregulated generation in ERCOT and PJM. | ||||||||||||||||||||||||||||
Marketing, risk management and retail activities in ERCOT, PJM and MISO. | ||||||||||||||||||||||||||||
AEP River Operations | ||||||||||||||||||||||||||||
Commercial barging operation that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. | ||||||||||||||||||||||||||||
The remainder of our activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also 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 months ended March 31, 2014 and 2013 and balance sheet information as of March 31, 2014 and December 31, 2013. These amounts include certain estimates and allocations where necessary. | ||||||||||||||||||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | ||||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Reconciling | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | Adjustments | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||||
External Customers | $ | 2,549 | (b) | $ | 1,161 | $ | 12 | $ | 821 | (b) | $ | 146 | $ | 10 | $ | -51 | (c) | $ | 4,648 | |||||||||
Other Operating Segments | 37 | (b) | 54 | 16 | 430 | (b) | 19 | 16 | -572 | - | ||||||||||||||||||
Total Revenues | $ | 2,586 | $ | 1,215 | $ | 28 | $ | 1,251 | $ | 165 | $ | 26 | $ | -623 | $ | 4,648 | ||||||||||||
Net Income (Loss) | $ | 279 | $ | 97 | $ | 24 | $ | 163 | $ | 3 | $ | -5 | $ | - | $ | 561 | ||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | ||||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Reconciling | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | Adjustments | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Three Months Ended March 31, 2013 | ||||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||||
External Customers | $ | 2,356 | $ | 1,090 | $ | 3 | $ | 258 | $ | 128 | $ | 5 | $ | -14 | (c) | $ | 3,826 | |||||||||||
Other Operating Segments | 159 | 44 | 5 | 662 | 5 | 13 | -888 | - | ||||||||||||||||||||
Total Revenues | $ | 2,515 | $ | 1,134 | $ | 8 | $ | 920 | $ | 133 | $ | 18 | $ | -902 | $ | 3,826 | ||||||||||||
Net Income (Loss) | $ | 181 | $ | 87 | $ | 12 | $ | 85 | $ | -2 | $ | 1 | $ | - | $ | 364 | ||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | Reconciling | |||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Adjustments | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | (d) | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
31-Mar-14 | ||||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 37,923 | $ | 12,339 | $ | 1,842 | $ | 8,302 | $ | 639 | $ | 321 | $ | -272 | $ | 61,094 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||||
Amortization | 12,424 | 3,382 | 13 | 3,460 | 197 | 176 | -88 | 19,564 | ||||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||||
Equipment - Net | $ | 25,499 | $ | 8,957 | $ | 1,829 | $ | 4,842 | $ | 442 | $ | 145 | $ | -184 | $ | 41,530 | ||||||||||||
Total Assets | $ | 32,997 | $ | 13,899 | $ | 2,460 | $ | 6,354 | $ | 659 | $ | 20,275 | $ | -19,606 | (e) | $ | 57,038 | |||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | Reconciling | |||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Adjustments | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | (d) | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 37,545 | $ | 12,143 | $ | 1,636 | $ | 8,277 | $ | 638 | $ | 315 | $ | -269 | $ | 60,285 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||||
Amortization | 12,250 | 3,342 | 10 | 3,409 | 189 | 173 | -85 | 19,288 | ||||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||||
Equipment - Net | $ | 25,295 | $ | 8,801 | $ | 1,626 | $ | 4,868 | $ | 449 | $ | 142 | $ | -184 | $ | 40,997 | ||||||||||||
Total Assets | $ | 32,791 | $ | 14,165 | $ | 2,245 | $ | 6,426 | $ | 673 | $ | 19,645 | $ | -19,531 | (e) | $ | 56,414 | |||||||||||
(a) Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | ||||||||||||||||||||||||||||
(b) Includes the impact of the corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. | ||||||||||||||||||||||||||||
(c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation. | ||||||||||||||||||||||||||||
(d) Includes eliminations due to an intercompany capital lease. | ||||||||||||||||||||||||||||
(e) 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 | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
Volume | |||||||||||||||||||||
March 31, | December 31, | Unit of | |||||||||||||||||||
2014 | 2013 | Measure | |||||||||||||||||||
Primary Risk Exposure | (in millions) | ||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | 320 | 406 | MWhs | ||||||||||||||||||
Coal | 4 | 4 | Tons | ||||||||||||||||||
Natural Gas | 123 | 127 | MMBtus | ||||||||||||||||||
Heating Oil and Gasoline | 4 | 6 | Gallons | ||||||||||||||||||
Interest Rate | $ | 192 | $ | 191 | USD | ||||||||||||||||
Interest Rate and Foreign Currency | $ | 819 | $ | 820 | 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 and natural gas (“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. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three months ended March 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 condensed balance sheets, we netted $19 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $17 million and $13 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 442 | $ | 23 | $ | 4 | $ | 469 | $ | -344 | $ | 125 | |||||||||
Long-term Risk Management Assets | 342 | 5 | - | 347 | -81 | 266 | |||||||||||||||
Total Assets | 784 | 28 | 4 | 816 | -425 | 391 | |||||||||||||||
Current Risk Management Liabilities | 384 | 16 | 1 | 401 | -341 | 60 | |||||||||||||||
Long-term Risk Management Liabilities | 205 | 4 | 13 | 222 | -85 | 137 | |||||||||||||||
Total Liabilities | 589 | 20 | 14 | 623 | -426 | 197 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 195 | $ | 8 | $ | -10 | $ | 193 | $ | 1 | $ | 194 | |||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 347 | $ | 12 | $ | 4 | $ | 363 | $ | -203 | $ | 160 | |||||||||
Long-term Risk Management Assets | 368 | 3 | - | 371 | -74 | 297 | |||||||||||||||
Total Assets | 715 | 15 | 4 | 734 | -277 | 457 | |||||||||||||||
Current Risk Management Liabilities | 292 | 11 | 1 | 304 | -214 | 90 | |||||||||||||||
Long-term Risk Management Liabilities | 237 | 3 | 15 | 255 | -78 | 177 | |||||||||||||||
Total Liabilities | 529 | 14 | 16 | 559 | -292 | 267 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 186 | $ | 1 | $ | -12 | $ | 175 | $ | 15 | $ | 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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||||||
Location of Gain (Loss) | 2014 | 2013 | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Vertically Integrated Utilities Revenues | $ | 18 | $ | 6 | |||||||||||||||||
Generation & Marketing Revenues | 32 | 16 | |||||||||||||||||||
Regulatory Assets (a) | - | 2 | |||||||||||||||||||
Regulatory Liabilities (a) | 89 | -6 | |||||||||||||||||||
Total Gain on Risk Management Contracts | $ | 139 | $ | 18 | |||||||||||||||||
(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 months ended March 31, 2014, we recognized gains of $2 million on our hedging instruments and offsetting losses of $2 million on our long-term debt. During the three months ended March 31, 2013, we recognized losses of $1 million on our hedging instruments and offsetting gains of $1 million on our long-term debt. During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, we designated heating oil and gasoline derivatives as cash flow hedges. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 13 | $ | - | $ | 13 | |||||||||||||||
Hedging Liabilities (a) | 5 | 2 | 7 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | 4 | -22 | -18 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | 3 | -4 | -1 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 7 | $ | - | $ | 7 | |||||||||||||||
Hedging Liabilities (a) | 6 | 2 | 8 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | - | -23 | -23 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | - | -4 | -4 | ||||||||||||||||||
(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 March 31, 2014, 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 41 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), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. 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 a specified rating threshold that would require the posting of additional collateral. 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 and guaranties for contractual obligations if our credit ratings had declined below a specified rating threshold and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | $ | 2 | $ | 3 | |||||||||||||||||
Amount of Collateral AEP Subsidiaries Would Have Been | |||||||||||||||||||||
Required to Post | 144 | 33 | |||||||||||||||||||
Amount Attributable to RTO and ISO Activities | 38 | 28 | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual | |||||||||||||||||||||
Netting Arrangements | $ | 225 | $ | 293 | |||||||||||||||||
Amount of Cash Collateral Posted | - | 1 | |||||||||||||||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 177 | 235 | |||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 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: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 34,483 | $ | 224 | $ | - | $ | 34,707 | $ | -18,735 | $ | 15,972 | |||||||||
Long-term Risk Management Assets | 17,304 | - | - | 17,304 | -3,291 | 14,013 | |||||||||||||||
Total Assets | 51,787 | 224 | - | 52,011 | -22,026 | 29,985 | |||||||||||||||
Current Risk Management Liabilities | 24,273 | 90 | - | 24,363 | -19,727 | 4,636 | |||||||||||||||
Long-term Risk Management Liabilities | 11,558 | - | - | 11,558 | -3,629 | 7,929 | |||||||||||||||
Total Liabilities | 35,831 | 90 | - | 35,921 | -23,356 | 12,565 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 15,956 | $ | 134 | $ | - | $ | 16,090 | $ | 1,330 | $ | 17,420 | |||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 46,431 | $ | 389 | $ | - | $ | 46,820 | $ | -25,649 | $ | 21,171 | |||||||||
Long-term Risk Management Assets | 20,948 | - | - | 20,948 | -4,000 | 16,948 | |||||||||||||||
Total Assets | 67,379 | 389 | - | 67,768 | -29,649 | 38,119 | |||||||||||||||
Current Risk Management Liabilities | 37,010 | 313 | - | 37,323 | -28,431 | 8,892 | |||||||||||||||
Long-term Risk Management Liabilities | 14,452 | - | - | 14,452 | -4,211 | 10,241 | |||||||||||||||
Total Liabilities | 51,462 | 313 | - | 51,775 | -32,642 | 19,133 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 15,917 | $ | 76 | $ | - | $ | 15,993 | $ | 2,993 | $ | 18,986 | |||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 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: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 26,273 | $ | 152 | $ | - | $ | 26,425 | $ | -13,867 | $ | 12,558 | |||||||||
Long-term Risk Management Assets | 11,737 | - | - | 11,737 | -2,232 | 9,505 | |||||||||||||||
Total Assets | 38,010 | 152 | - | 38,162 | -16,099 | 22,063 | |||||||||||||||
Current Risk Management Liabilities | 18,614 | 61 | - | 18,675 | -14,541 | 4,134 | |||||||||||||||
Long-term Risk Management Liabilities | 7,839 | - | - | 7,839 | -2,461 | 5,378 | |||||||||||||||
Total Liabilities | 26,453 | 61 | - | 26,514 | -17,002 | 9,512 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 11,557 | $ | 91 | $ | - | $ | 11,648 | $ | 903 | $ | 12,551 | |||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 33,229 | $ | 234 | $ | - | $ | 33,463 | $ | -18,075 | $ | 15,388 | |||||||||
Long-term Risk Management Assets | 14,208 | - | - | 14,208 | -2,713 | 11,495 | |||||||||||||||
Total Assets | 47,437 | 234 | - | 47,671 | -20,788 | 26,883 | |||||||||||||||
Current Risk Management Liabilities | 26,779 | 212 | - | 26,991 | -19,962 | 7,029 | |||||||||||||||
Long-term Risk Management Liabilities | 9,802 | - | - | 9,802 | -2,856 | 6,946 | |||||||||||||||
Total Liabilities | 36,581 | 212 | - | 36,793 | -22,818 | 13,975 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 10,856 | $ | 22 | $ | - | $ | 10,878 | $ | 2,030 | $ | 12,908 | |||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 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: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 4,066 | $ | - | $ | - | $ | 4,066 | $ | -86 | $ | 3,980 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 4,066 | - | - | 4,066 | -86 | 3,980 | |||||||||||||||
Current Risk Management Liabilities | 83 | - | - | 83 | -83 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 83 | - | - | 83 | -83 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 3,983 | $ | - | $ | - | $ | 3,983 | $ | -3 | $ | 3,980 | |||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 3,269 | $ | 162 | $ | - | $ | 3,431 | $ | -349 | $ | 3,082 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 3,269 | 162 | - | 3,431 | -349 | 3,082 | |||||||||||||||
Current Risk Management Liabilities | 349 | - | - | 349 | -349 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 349 | - | - | 349 | -349 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 2,920 | $ | 162 | $ | - | $ | 3,082 | $ | - | $ | 3,082 | |||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 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: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 1,403 | $ | - | $ | - | $ | 1,403 | $ | -54 | $ | 1,349 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,403 | - | - | 1,403 | -54 | 1,349 | |||||||||||||||
Current Risk Management Liabilities | 136 | - | - | 136 | -53 | 83 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 136 | - | - | 136 | -53 | 83 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,267 | $ | - | $ | - | $ | 1,267 | $ | -1 | $ | 1,266 | |||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 1,078 | $ | 84 | $ | - | $ | 1,162 | $ | 5 | $ | 1,167 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,078 | 84 | - | 1,162 | 5 | 1,167 | |||||||||||||||
Current Risk Management Liabilities | 81 | - | - | 81 | 4 | 85 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 81 | - | - | 81 | 4 | 85 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 997 | $ | 84 | $ | - | $ | 1,081 | $ | 1 | $ | 1,082 | |||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
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, natural gas, 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 extent, heating oil, gasoline 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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 March 31, 2014 and December 31, 2013 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: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 2,080 | $ | - | $ | - | $ | 2,080 | $ | -173 | $ | 1,907 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 2,080 | - | - | 2,080 | -173 | 1,907 | |||||||||||||||
Current Risk Management Liabilities | 171 | - | - | 171 | -171 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 171 | - | - | 171 | -171 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,909 | $ | - | $ | - | $ | 1,909 | $ | -2 | $ | 1,907 | |||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 1,233 | $ | 97 | $ | - | $ | 1,330 | $ | -151 | $ | 1,179 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,233 | 97 | - | 1,330 | -151 | 1,179 | |||||||||||||||
Current Risk Management Liabilities | 154 | - | - | 154 | -154 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 154 | - | - | 154 | -154 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,079 | $ | 97 | $ | - | $ | 1,176 | $ | 3 | $ | 1,179 | |||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, 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 months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. | |||||||||||||||||||||
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 months ended March 31, 2014 and 2013, I&M 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 months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. | |||||||||||||||||||||
During the three months ended March 31, 2014 and 2013, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were: | |||||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 |
Fair_Value_Measurements
Fair Value Measurements | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
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 amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply's President and Vice President. | |||||||||||||||||||||
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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Book Value | Fair Value | Book Value | Fair Value | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Long-term Debt | $ | 18,087 | $ | 19,738 | $ | 18,377 | $ | 19,672 | |||||||||||||
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: | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 206 | $ | - | $ | - | $ | 206 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | 80 | |||||||||||||||||
Equity Securities - Mutual Funds | 13 | 11 | - | 24 | |||||||||||||||||
Total Other Temporary Investments | $ | 299 | $ | 11 | $ | - | $ | 310 | |||||||||||||
31-Dec-13 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 250 | $ | - | $ | - | $ | 250 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | 80 | |||||||||||||||||
Equity Securities - Mutual Funds | 12 | 11 | - | 23 | |||||||||||||||||
Total Other Temporary Investments | $ | 342 | $ | 11 | $ | - | $ | 353 | |||||||||||||
(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 months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | - | $ | - | |||||||||||||||||
Purchases of Investments | 1 | 11 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | - | - | |||||||||||||||||||
Gross Realized Losses on Investment Sales | - | - | |||||||||||||||||||
As of March 31, 2014 and December 31, 2013, we had no Other Temporary Investments with an unrealized loss position. As of March 31, 2014, 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 months ended March 31, 2014 and 2013, see Note 3. | |||||||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 12 | $ | - | $ | - | $ | 19 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 606 | 31 | -4 | 609 | 26 | -4 | |||||||||||||||
Corporate Debt | 43 | 4 | -1 | 37 | 2 | -1 | |||||||||||||||
State and Local Government | 281 | 1 | - | 255 | 1 | - | |||||||||||||||
Subtotal Fixed Income Securities | 930 | 36 | -5 | 901 | 29 | -5 | |||||||||||||||
Equity Securities - Domestic | 1,020 | 514 | -80 | 1,012 | 506 | -82 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,962 | $ | 550 | $ | -85 | $ | 1,932 | $ | 535 | $ | -87 | |||||||||
The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 148 | $ | 168 | |||||||||||||||||
Purchases of Investments | 164 | 185 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | 8 | 3 | |||||||||||||||||||
Gross Realized Losses on Investment Sales | 1 | 2 | |||||||||||||||||||
The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively. The adjusted cost of equity securities was $506 million and $506 million as of March 31, 2014 and December 31, 2013, respectively. | |||||||||||||||||||||
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows: | |||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Within 1 year | $ | 82 | |||||||||||||||||||
1 year – 5 years | 386 | ||||||||||||||||||||
5 years – 10 years | 193 | ||||||||||||||||||||
After 10 years | 269 | ||||||||||||||||||||
Total | $ | 930 | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 16 | $ | 1 | $ | - | $ | 275 | $ | 292 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 187 | 7 | - | 12 | 206 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | - | 80 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 24 | - | - | - | 24 | ||||||||||||||||
Total Other Temporary Investments | 291 | 7 | - | 12 | 310 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | 20 | 586 | 128 | -364 | 370 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 21 | 2 | -10 | 13 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 4 | 4 | ||||||||||||||||
Total Risk Management Assets | 20 | 609 | 130 | -368 | 391 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 3 | - | - | 9 | 12 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 606 | - | - | 606 | ||||||||||||||||
Corporate Debt | - | 43 | - | - | 43 | ||||||||||||||||
State and Local Government | - | 281 | - | - | 281 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 930 | - | - | 930 | ||||||||||||||||
Equity Securities - Domestic (b) | 1,020 | - | - | - | 1,020 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,023 | 930 | - | 9 | 1,962 | ||||||||||||||||
Total Assets | $ | 1,350 | $ | 1,547 | $ | 130 | $ | -72 | $ | 2,955 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | $ | 30 | $ | 485 | $ | 25 | $ | -362 | $ | 178 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 15 | - | -10 | 5 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 10 | - | 2 | 12 | ||||||||||||||||
Total Risk Management Liabilities | $ | 30 | $ | 512 | $ | 25 | $ | -370 | $ | 197 | |||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 16 | $ | 1 | $ | - | $ | 101 | $ | 118 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 231 | 8 | - | 11 | 250 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | - | 80 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 23 | - | - | - | 23 | ||||||||||||||||
Total Other Temporary Investments | 334 | 8 | - | 11 | 353 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | 22 | 549 | 142 | -273 | 440 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 15 | - | -8 | 7 | ||||||||||||||||
Fair Value Hedges | - | 1 | - | 3 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 6 | 6 | ||||||||||||||||
Total Risk Management Assets | 22 | 565 | 142 | -272 | 457 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 8 | - | - | 11 | 19 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 609 | - | - | 609 | ||||||||||||||||
Corporate Debt | - | 37 | - | - | 37 | ||||||||||||||||
State and Local Government | - | 255 | - | - | 255 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 901 | - | - | 901 | ||||||||||||||||
Equity Securities - Domestic (b) | 1,012 | - | - | - | 1,012 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,020 | 901 | - | 11 | 1,932 | ||||||||||||||||
Total Assets | $ | 1,392 | $ | 1,475 | $ | 142 | $ | -149 | $ | 2,860 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | $ | 30 | $ | 475 | $ | 22 | $ | -282 | $ | 245 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 11 | 3 | -8 | 6 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 11 | - | 3 | 14 | ||||||||||||||||
Total Risk Management Liabilities | $ | 30 | $ | 499 | $ | 25 | $ | -287 | $ | 267 | |||||||||||
(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 March 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. 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, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 117 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | 84 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | -10 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 9 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -100 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | -4 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -2 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 11 | ||||||||||||||||||||
Balance as of March 31, 2014 | $ | 105 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Three Months Ended March 31, 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) | -4 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | -5 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 1 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -6 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 6 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | - | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | -2 | ||||||||||||||||||||
Balance as of March 31, 2013 | $ | 76 | |||||||||||||||||||
(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 our Level 3 positions as of March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Fair Value | Valuation | Significant | Input/Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 116 | $ | 23 | Discounted Cash Flow | Forward Market Price (a) | $ | 1.45 | $ | 131.46 | |||||||||||
Counterparty Credit Risk (b) | 315 | ||||||||||||||||||||
FTRs | 14 | 2 | Discounted Cash Flow | Forward Market Price (a) | -5.05 | 9.17 | |||||||||||||||
Total | $ | 130 | $ | 25 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Fair Value | Valuation | Significant | Input/Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 132 | $ | 22 | Discounted Cash Flow | Forward Market Price (a) | $ | 11.42 | $ | 120.72 | |||||||||||
Counterparty Credit Risk (b) | 316 | ||||||||||||||||||||
FTRs | 10 | 3 | Discounted Cash Flow | Forward Market Price (a) | -5.1 | 10.44 | |||||||||||||||
Total | $ | 142 | $ | 25 | |||||||||||||||||
(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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 13,536 | $ | - | $ | - | $ | 36 | $ | 13,572 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | 393 | 37,854 | 10,508 | -18,979 | 29,776 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 224 | - | -15 | 209 | ||||||||||||||||
Total Risk Management Assets | 393 | 38,078 | 10,508 | -18,994 | 29,985 | ||||||||||||||||
Total Assets: | $ | 13,929 | $ | 38,078 | $ | 10,508 | $ | -18,958 | $ | 43,557 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 306 | $ | 29,386 | $ | 3,107 | $ | -20,309 | $ | 12,490 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 90 | - | -15 | 75 | ||||||||||||||||
Total Risk Management Liabilities | $ | 306 | $ | 29,476 | $ | 3,107 | $ | -20,324 | $ | 12,565 | |||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 2,714 | $ | - | $ | - | $ | 36 | $ | 2,750 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | 827 | 54,448 | 12,097 | -29,616 | 37,756 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 389 | - | -26 | 363 | ||||||||||||||||
Total Risk Management Assets | 827 | 54,837 | 12,097 | -29,642 | 38,119 | ||||||||||||||||
Total Assets | $ | 3,541 | $ | 54,837 | $ | 12,097 | $ | -29,606 | $ | 40,869 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 700 | $ | 49,220 | $ | 1,535 | $ | -32,609 | $ | 18,846 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 313 | - | -26 | 287 | ||||||||||||||||
Total Risk Management Liabilities | $ | 700 | $ | 49,533 | $ | 1,535 | $ | -32,635 | $ | 19,133 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 6,454 | $ | 2,822 | Discounted Cash Flow | Forward Market Price | $ | 13.34 | $ | 59.6 | |||||||||||
FTRs | 4,054 | 285 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 10,508 | $ | 3,107 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 9,359 | $ | 960 | Discounted Cash Flow | Forward Market Price | $ | 13.04 | $ | 80.5 | |||||||||||
FTRs | 2,738 | 575 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 12,097 | $ | 1,535 | |||||||||||||||||
(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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 12,439 | $ | - | $ | - | $ | 18,804 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 606,228 | 31,666 | -3,621 | 608,875 | 26,114 | -3,824 | |||||||||||||||
Corporate Debt | 42,727 | 3,223 | -1,097 | 36,782 | 2,450 | -1,123 | |||||||||||||||
State and Local Government | 280,612 | 972 | -345 | 254,638 | 748 | -370 | |||||||||||||||
Subtotal Fixed Income Securities | 929,567 | 35,861 | -5,063 | 900,295 | 29,312 | -5,317 | |||||||||||||||
Equity Securities - Domestic | 1,020,145 | 513,803 | -79,563 | 1,012,511 | 505,538 | -81,677 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,962,151 | $ | 549,664 | $ | -84,626 | $ | 1,931,610 | $ | 534,850 | $ | -86,994 | |||||||||
The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013: | |||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 147,700 | $ | 167,670 | |||||||||||||||||
Purchases of Investments | 164,511 | 184,299 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | 8,141 | 3,323 | |||||||||||||||||||
Gross Realized Losses on Investment Sales | 874 | 2,315 | |||||||||||||||||||
The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively. The adjusted cost of equity securities was $506 million and $506 million as of March 31, 2014 and December 31, 2013, respectively. | |||||||||||||||||||||
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows: | |||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Within 1 year | $ | 82,190 | |||||||||||||||||||
1 year – 5 years | 386,173 | ||||||||||||||||||||
5 years – 10 years | 193,018 | ||||||||||||||||||||
After 10 years | 268,186 | ||||||||||||||||||||
Total | $ | 929,567 | |||||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 267 | $ | 28,746 | $ | 6,945 | $ | -14,037 | $ | 21,921 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 152 | - | -10 | 142 | ||||||||||||||||
Total Risk Management Assets | 267 | 28,898 | 6,945 | -14,047 | 22,063 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (d) | 3,576 | - | - | 8,863 | 12,439 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 606,228 | - | - | 606,228 | ||||||||||||||||
Corporate Debt | - | 42,727 | - | - | 42,727 | ||||||||||||||||
State and Local Government | - | 280,612 | - | - | 280,612 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 929,567 | - | - | 929,567 | ||||||||||||||||
Equity Securities - Domestic (e) | 1,020,145 | - | - | - | 1,020,145 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,023,721 | 929,567 | - | 8,863 | 1,962,151 | ||||||||||||||||
Total Assets | $ | 1,023,988 | $ | 958,465 | $ | 6,945 | $ | -5,184 | $ | 1,984,214 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 208 | $ | 22,089 | $ | 2,104 | $ | -14,940 | $ | 9,461 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 61 | - | -10 | 51 | ||||||||||||||||
Total Risk Management Liabilities | $ | 208 | $ | 22,150 | $ | 2,104 | $ | -14,950 | $ | 9,512 | |||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 561 | $ | 38,667 | $ | 8,205 | $ | -20,766 | $ | 26,667 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 234 | - | -18 | 216 | ||||||||||||||||
Total Risk Management Assets | 561 | 38,901 | 8,205 | -20,784 | 26,883 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (d) | 8,082 | - | - | 10,722 | 18,804 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 608,875 | - | - | 608,875 | ||||||||||||||||
Corporate Debt | - | 36,782 | - | - | 36,782 | ||||||||||||||||
State and Local Government | - | 254,638 | - | - | 254,638 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 900,295 | - | - | 900,295 | ||||||||||||||||
Equity Securities - Domestic (e) | 1,012,511 | - | - | - | 1,012,511 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,020,593 | 900,295 | - | 10,722 | 1,931,610 | ||||||||||||||||
Total Assets | $ | 1,021,154 | $ | 939,196 | $ | 8,205 | $ | -10,062 | $ | 1,958,493 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 475 | $ | 35,061 | $ | 1,041 | $ | -22,796 | $ | 13,781 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 212 | - | -18 | 194 | ||||||||||||||||
Total Risk Management Liabilities | $ | 475 | $ | 35,273 | $ | 1,041 | $ | -22,814 | $ | 13,975 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 4,378 | $ | 1,914 | Discounted Cash Flow | Forward Market Price | $ | 13.34 | $ | 59.6 | |||||||||||
FTRs | 2,567 | 190 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 6,945 | $ | 2,104 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 6,348 | $ | 651 | Discounted Cash Flow | Forward Market Price | $ | 13.04 | $ | 80.5 | |||||||||||
FTRs | 1,857 | 390 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 8,205 | $ | 1,041 | |||||||||||||||||
(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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 32,054 | $ | - | $ | - | $ | 12 | $ | 32,066 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 76 | 3,990 | -86 | 3,980 | ||||||||||||||||
Total Assets | $ | 32,054 | $ | 76 | $ | 3,990 | $ | -74 | $ | 36,046 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 5 | $ | 78 | $ | -83 | $ | - | |||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 19,387 | $ | - | $ | - | $ | 12 | $ | 19,399 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | - | 3,269 | -349 | 2,920 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 162 | - | - | 162 | ||||||||||||||||
Total Risk Management Assets | - | 162 | 3,269 | -349 | 3,082 | ||||||||||||||||
Total Assets | $ | 19,387 | $ | 162 | $ | 3,269 | $ | -337 | $ | 22,481 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | - | $ | 349 | $ | -349 | $ | - | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 3,990 | 78 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 3,990 | $ | 78 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 3,269 | 349 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 3,269 | $ | 349 | |||||||||||||||||
(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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 922 | $ | 481 | $ | -54 | $ | 1,349 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 4 | $ | 132 | $ | -53 | $ | 83 | |||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 1,078 | $ | - | $ | 5 | $ | 1,083 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 84 | - | - | 84 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,162 | $ | - | $ | 5 | $ | 1,167 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 81 | $ | - | $ | 4 | $ | 85 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
PSO | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 481 | 132 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 481 | $ | 132 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 March 31, 2014 and December 31, 2013 are summarized in the following table: | |||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
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 March 31, 2014 and December 31, 2013. 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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 15,537 | $ | - | $ | - | $ | 2,458 | $ | 17,995 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 1,471 | 609 | -173 | 1,907 | ||||||||||||||||
Total Assets | $ | 15,537 | $ | 1,471 | $ | 609 | $ | 2,285 | $ | 19,902 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 4 | $ | 167 | $ | -171 | $ | - | |||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 15,871 | $ | - | $ | - | $ | 1,370 | $ | 17,241 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 1,233 | - | -151 | 1,082 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 97 | - | - | 97 | ||||||||||||||||
Total Risk Management Assets | - | 1,330 | - | -151 | 1,179 | ||||||||||||||||
Total Assets | $ | 15,871 | $ | 1,330 | $ | - | $ | 1,219 | $ | 18,420 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 154 | $ | - | $ | -154 | $ | - | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013. | |||||||||||||||||||||
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 March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 March 31, 2014 and December 31, 2013: | |||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 609 | 167 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 609 | $ | 167 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. |
Income_Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2014 | |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. We are currently under examination in several state and local jurisdictions. However, it is possible 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 2009. | |
Appalachian Power Co [Member] | ' |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. | |
Indiana Michigan Power Co [Member] | ' |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. | |
Ohio Power Co [Member] | ' |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. | |
Public Service Co Of Oklahoma [Member] | ' |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. | |
Southwestern Electric Power Co [Member] | ' |
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 IRS examination of years 2011 and 2012 started in April 2014. 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. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. |
Financing_Activities
Financing Activities | 3 Months Ended | |||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||
Financing Activities | ' | |||||||||||||||||||
11. FINANCING ACTIVITIES | ||||||||||||||||||||
Long-term Debt | ||||||||||||||||||||
The following table details long-term debt outstanding as of March 31, 2014 and December 31, 2013: | ||||||||||||||||||||
Type of Debt | 31-Mar-14 | 31-Dec-13 | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Senior Unsecured Notes | $ | 11,571 | $ | 11,799 | ||||||||||||||||
Pollution Control Bonds | 1,932 | 1,932 | ||||||||||||||||||
Notes Payable | 342 | 369 | ||||||||||||||||||
Securitization Bonds | 2,574 | 2,686 | ||||||||||||||||||
Spent Nuclear Fuel Obligation (a) | 265 | 265 | ||||||||||||||||||
Other Long-term Debt | 1,434 | 1,360 | ||||||||||||||||||
Fair Value of Interest Rate Hedges | -7 | -9 | ||||||||||||||||||
Unamortized Discount, Net | -24 | -25 | ||||||||||||||||||
Total Long-term Debt Outstanding | 18,087 | 18,377 | ||||||||||||||||||
Long-term Debt Due Within One Year | 1,612 | 1,549 | ||||||||||||||||||
Long-term Debt | $ | 16,475 | $ | 16,828 | ||||||||||||||||
(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 $309 million as of March 31, 2014 and December 31, 2013, 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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount | Rate | Due Date | ||||||||||||||||
Issuances: | (in millions) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50 | Variable | 2016 | |||||||||||||||
Non-Registrant: | ||||||||||||||||||||
Transource Missouri | Other Long-term Debt | 27 | Variable | 2018 | ||||||||||||||||
Total Issuances | $ | 77 | (a) | |||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in millions) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
I&M | Notes Payable | $ | 5 | Variable | 2016 | |||||||||||||||
I&M | Notes Payable | 4 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 5 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 2 | Variable | 2015 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225 | 4.85 | 2014 | ||||||||||||||||
SWEPCo | Notes Payable | 2 | 4.58 | 2032 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEGCo | Senior Unsecured Notes | 4 | 6.33 | 2037 | ||||||||||||||||
AEP Subsidiaries | Notes Payable | 1 | Variable | 2017 | ||||||||||||||||
TCC | Securitization Bonds | 72 | 5.09 | 2015 | ||||||||||||||||
TCC | Securitization Bonds | 40 | 6.25 | 2016 | ||||||||||||||||
Total Retirements and | ||||||||||||||||||||
Principal Payments | $ | 370 | ||||||||||||||||||
(a) 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 April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel. | ||||||||||||||||||||
As of March 31, 2014, 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 primarily 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: | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Type of Debt | Amount | Rate (a) | Amount | Rate (a) | ||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||
Securitized Debt for Receivables (b) | $ | 700 | 0.24 | % | $ | 700 | 0.23 | % | ||||||||||||
Commercial Paper | 632 | 0.31 | % | 57 | 0.29 | % | ||||||||||||||
Total Short-term Debt | $ | 1,332 | $ | 757 | ||||||||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | ||||||||||||||||||||
Credit Facilities | ||||||||||||||||||||
For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5. | ||||||||||||||||||||
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. | ||||||||||||||||||||
Our receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. We intend to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
Accounts receivable information for AEP Credit is as follows: | ||||||||||||||||||||
Three Months Ended | ||||||||||||||||||||
March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
(dollars in millions) | ||||||||||||||||||||
Effective Interest Rates on Securitization of Accounts Receivable | 0.24 | % | 0.23 | % | ||||||||||||||||
Net Uncollectible Accounts Receivable Written Off | $ | 8 | $ | 7 | ||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Accounts Receivable Retained Interest and Pledged as Collateral | ||||||||||||||||||||
Less Uncollectible Accounts | $ | 997 | $ | 929 | ||||||||||||||||
Total Principal Outstanding | 700 | 700 | ||||||||||||||||||
Delinquent Securitized Accounts Receivable | 55 | 45 | ||||||||||||||||||
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | 17 | 16 | ||||||||||||||||||
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | 278 | 331 | ||||||||||||||||||
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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 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. | ||||||||||||||||||||
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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. | ||||||||||||||||||||
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 PSO 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 5. | ||||||||||||||||||||
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. | ||||||||||||||||||||
AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows: | ||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 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. | ||||||||||||||||||||
In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel. | ||||||||||||||||||||
As of March 31, 2014, 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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. | ||||||||||||||||||||
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 PSO 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 5. | ||||||||||||||||||||
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. | ||||||||||||||||||||
AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows: | ||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 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. | ||||||||||||||||||||
As of March 31, 2014, 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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. | ||||||||||||||||||||
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 PSO 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Credit Facilities | ||||||||||||||||||||
For a discussion of credit facilities, see “Letters of Credit” section of Note 5. | ||||||||||||||||||||
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. | ||||||||||||||||||||
AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows: | ||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 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. | ||||||||||||||||||||
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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. | ||||||||||||||||||||
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 PSO 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
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. | ||||||||||||||||||||
AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows: | ||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
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 three months of 2014 are shown in the tables below: | ||||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 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. | ||||||||||||||||||||
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 generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. | ||||||||||||||||||||
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 PSO 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 March 31, 2014 and December 31, 2013 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 three months ended March 31, 2014 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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
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. | ||||||||||||||||||||
AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity. | ||||||||||||||||||||
The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows: | ||||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were: | ||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 |
Variable_Interest_Entities
Variable Interest Entities | 3 Months Ended | |||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||
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, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy. In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, our protected cell of EIS and Transource Energy 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 March 31, 2014 and 2013 were $39 million and $44 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 II 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 March 31, 2014 and 2013 were $25 million and $26 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 concluded that we are the primary beneficiary and are required to consolidate AEP Credit. See the tables below for the classification of AEP Credit's assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivables – 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 billion and $2 billion as of March 31, 2014 and December 31, 2013, respectively. Transition Funding has securitized transition assets of $1.8 billion and $1.9 billion as of March 31, 2014 and December 31, 2013, respectively. 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 and $267 million as of March 31, 2014 and December 31, 2013, respectively. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively. 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 sheets. | ||||||||||||||||||||||||||
Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $380 million and $380 million as of March 31, 2014 and December 31, 2013, respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 million as of March 31, 2014 and December 31, 2013, respectively. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets. | ||||||||||||||||||||||||||
The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets on the condensed balance sheets. | ||||||||||||||||||||||||||
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 EIS. Our insurance premium expense to the protected cell for the three months ended March 31, 2014 and 2013 was $16 million and $15 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. | ||||||||||||||||||||||||||
Transource Energy was formed for the purpose of investing in utilities which develop, acquire, construct, own and operate transmission facilities in accordance with FERC-approved rates. AEP has equity and voting ownership of 86.5% with the other owner having 13.5% interest. Management has concluded that Transource Energy is a VIE and that AEP is the primary beneficiary because AEP has the power to direct the most significant activities of the entity. AEP's equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri acquired transmission assets from the non-controlling owner and issued debt and received capital contributions to fund the acquisition. The majority of Transource Energy's activity resulted from the asset acquisition, debt issuance and capital contribution. See the table below for the classification of Transource Energy's assets and liabilities on the condensed balance sheets. | ||||||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
31-Mar-14 | ||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
APCo | ||||||||||||||||||||||||||
OPCo | Appalachian | |||||||||||||||||||||||||
Ohio | Consumer | |||||||||||||||||||||||||
TCC | Phase-in- | Rate | Protected | |||||||||||||||||||||||
SWEPCo | I&M | AEP | Transition | Recovery | Relief | Cell | Transource | |||||||||||||||||||
Sabine | DCC Fuel | Credit | Funding | Funding | Funding | of EIS | Energy | |||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||
Current Assets | $ | 62 | $ | 109 | $ | 1,004 | $ | 166 | $ | 36 | $ | 16 | $ | 152 | $ | 4 | ||||||||||
Net Property, Plant and | ||||||||||||||||||||||||||
Equipment | 154 | 129 | - | - | - | - | - | 57 | ||||||||||||||||||
Other Noncurrent Assets | 50 | 45 | - | 1,861 | (a) | 242 | (b) | 374 | (c) | 3 | 5 | |||||||||||||||
Total Assets | $ | 266 | $ | 283 | $ | 1,004 | $ | 2,027 | $ | 278 | $ | 390 | $ | 155 | $ | 66 | ||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 29 | $ | 100 | $ | 894 | $ | 304 | $ | 60 | $ | 28 | $ | 48 | $ | 18 | ||||||||||
Noncurrent Liabilities | 236 | 183 | 1 | 1,705 | 217 | 360 | 67 | 28 | ||||||||||||||||||
Equity | 1 | - | 109 | 18 | 1 | 2 | 40 | 20 | ||||||||||||||||||
Total Liabilities and Equity | $ | 266 | $ | 283 | $ | 1,004 | $ | 2,027 | $ | 278 | $ | 390 | $ | 155 | $ | 66 | ||||||||||
(a) Includes an intercompany item eliminated in consolidation of $81 million. | ||||||||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $112 million. | ||||||||||||||||||||||||||
(c) Includes an intercompany item eliminated in consolidation of $4 million. | ||||||||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | ||||||||||||||||||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
APCo | ||||||||||||||||||||||||||
OPCo | Appalachian | |||||||||||||||||||||||||
Ohio | Consumer | |||||||||||||||||||||||||
TCC | Phase-in- | Rate | ||||||||||||||||||||||||
SWEPCo | I&M | AEP | Transition | Recovery | Relief | Protected Cell | ||||||||||||||||||||
Sabine | DCC Fuel | Credit | Funding | Funding | Funding | of EIS | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||
Current Assets | $ | 67 | $ | 118 | $ | 935 | $ | 232 | $ | 23 | $ | 6 | $ | 143 | ||||||||||||
Net Property, Plant and Equipment | 157 | 157 | - | - | - | - | - | |||||||||||||||||||
Other Noncurrent Assets | 51 | 60 | 1 | 1,918 | (a) | 252 | (b) | 378 | (c) | 3 | ||||||||||||||||
Total Assets | $ | 275 | $ | 335 | $ | 936 | $ | 2,150 | $ | 275 | $ | 384 | $ | 146 | ||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 33 | $ | 108 | $ | 827 | $ | 312 | $ | 37 | $ | 14 | $ | 39 | ||||||||||||
Noncurrent Liabilities | 242 | 227 | 1 | 1,820 | 237 | 368 | 66 | |||||||||||||||||||
Equity | - | - | 108 | 18 | 1 | 2 | 41 | |||||||||||||||||||
Total Liabilities and Equity | $ | 275 | $ | 335 | $ | 936 | $ | 2,150 | $ | 275 | $ | 384 | $ | 146 | ||||||||||||
(a) Includes an intercompany item eliminated in consolidation of $82 million. | ||||||||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $116 million. | ||||||||||||||||||||||||||
(c) Includes an intercompany item eliminated in consolidation of $4 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 March 31, 2014 and 2013 were $2 million and $18 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: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
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 | 2 | 2 | 1 | 1 | ||||||||||||||||||||||
SWEPCo's Guarantee of Debt | - | 85 | - | 61 | ||||||||||||||||||||||
Total Investment in DHLC | $ | 10 | $ | 95 | $ | 9 | $ | 70 | ||||||||||||||||||
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 September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement. In March 2014, the settlement judge recommended termination of the settlement proceedings and this case is expected to proceed to a hearing. | ||||||||||||||||||||||||||
Our investment in PATH-WV was: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
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 | 6 | 6 | 6 | 6 | ||||||||||||||||||||||
Total Investment in PATH-WV | $ | 25 | $ | 25 | $ | 25 | $ | 25 | ||||||||||||||||||
As of March 31, 2014, our $25 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows. | ||||||||||||||||||||||||||
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. APCo is the primary beneficiary of Appalachian Consumer Rate Relief 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. | ||||||||||||||||||||||||||
Appalachian Consumer Rate Relief Funding was formed for the sole purpose of issuing and servicing securitization bonds related to APCo's under-recovered ENEC deferral balance. Management has concluded that APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding because APCo has the power to direct the most significant activities of the VIE and APCo's equity interest could potentially be significant. Therefore, APCo is required to consolidate Appalachian Consumer Rate Relief Funding. The securitized bonds totaled $380 million and $380 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect WV deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. | ||||||||||||||||||||||||||
The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. | ||||||||||||||||||||||||||
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | ||||||||||||||||||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Appalachian Consumer | ||||||||||||||||||||||||||
Rate Relief Funding | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 15,981 | $ | 5,891 | ||||||||||||||||||||||
Other Noncurrent Assets (a) | 373,521 | 378,029 | ||||||||||||||||||||||||
Total Assets | $ | 389,502 | $ | 383,920 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 27,682 | $ | 14,000 | ||||||||||||||||||||||
Noncurrent Liabilities | 359,919 | 368,018 | ||||||||||||||||||||||||
Equity | 1,901 | 1,902 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 389,502 | $ | 383,920 | ||||||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively. | ||||||||||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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. APCo is the primary beneficiary of Appalachian Consumer Rate Relief 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 II 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 March 31, 2014 and 2013 were $25 million and $26 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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
DCC Fuel | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 109,374 | $ | 117,762 | ||||||||||||||||||||||
Net Property, Plant and Equipment | 129,013 | 156,820 | ||||||||||||||||||||||||
Other Noncurrent Assets | 44,853 | 60,450 | ||||||||||||||||||||||||
Total Assets | $ | 283,240 | $ | 335,032 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 100,141 | $ | 107,815 | ||||||||||||||||||||||
Noncurrent Liabilities | 183,099 | 227,217 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 283,240 | $ | 335,032 | ||||||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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 has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report. | ||||||||||||||||||||||||||
Total billings from AEGCo were as follows: | ||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 70,422 | $ | 58,535 | ||||||||||||||||||||||
OPCo | - | 38,711 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | |||||||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 24,364 | $ | 24,364 | $ | 23,916 | $ | 23,916 | ||||||||||||||||||
OPCo | - | - | 12,810 | 12,810 | ||||||||||||||||||||||
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. APCo is the primary beneficiary of Appalachian Consumer Rate Relief 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 and $267 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets. 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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Ohio Phase-in- | ||||||||||||||||||||||||||
Recovery Funding | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 35,958 | $ | 23,198 | ||||||||||||||||||||||
Other Noncurrent Assets (a) | 241,814 | 251,409 | ||||||||||||||||||||||||
Total Assets | $ | 277,772 | $ | 274,607 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 59,590 | $ | 36,470 | ||||||||||||||||||||||
Noncurrent Liabilities | 216,845 | 236,800 | ||||||||||||||||||||||||
Equity | 1,337 | 1,337 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 277,772 | $ | 274,607 | ||||||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively. | ||||||||||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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 has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report. | ||||||||||||||||||||||||||
Total billings from AEGCo were as follows: | ||||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 70,422 | $ | 58,535 | ||||||||||||||||||||||
OPCo | - | 38,711 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | |||||||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 24,364 | $ | 24,364 | $ | 23,916 | $ | 23,916 | ||||||||||||||||||
OPCo | - | - | 12,810 | 12,810 | ||||||||||||||||||||||
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. APCo is the primary beneficiary of Appalachian Consumer Rate Relief 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 March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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. APCo is the primary beneficiary of Appalachian Consumer Rate Relief 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 March 31, 2014 and 2013 were $39 million and $44 million, respectively. See the tables 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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Sabine | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 61,675 | $ | 66,478 | ||||||||||||||||||||||
Net Property, Plant and Equipment | 153,928 | 157,274 | ||||||||||||||||||||||||
Other Noncurrent Assets | 50,140 | 51,211 | ||||||||||||||||||||||||
Total Assets | $ | 265,743 | $ | 274,963 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 29,257 | $ | 32,812 | ||||||||||||||||||||||
Noncurrent Liabilities | 236,142 | 241,673 | ||||||||||||||||||||||||
Equity | 344 | 478 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 265,743 | $ | 274,963 | ||||||||||||||||||||||
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 March 31, 2014 and 2013 were $2 million and $18 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: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
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 | 1,910 | 1,910 | 1,600 | 1,600 | ||||||||||||||||||||||
SWEPCo's Guarantee of Debt | - | 85,190 | - | 61,348 | ||||||||||||||||||||||
Total Investment in DHLC | $ | 9,553 | $ | 94,743 | $ | 9,243 | $ | 70,591 | ||||||||||||||||||
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 March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows: | ||||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 |
Significant_Accounting_Matters1
Significant Accounting Matters (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014. | |
Revenue Recognition | ' |
Revenue Recognition | |
Electricity Supply and Delivery Activities – Transactions with PJM | |
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |
APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |
AEP's nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales. | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |
Revenue Recognition | ' |
Revenue Recognition | |
Electricity Supply and Delivery Activities – Transactions with PJM | |
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |
APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |
Revenue Recognition | ' |
Revenue Recognition | |
Electricity Supply and Delivery Activities – Transactions with PJM | |
Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. | |
APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices. | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. | |
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 months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014. |
Derivatives_and_Hedging_Polici
Derivatives and Hedging (Policies) | 3 Months Ended |
Mar. 31, 2014 | |
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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three months ended March 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. 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 a specified rating threshold that would require the posting of additional collateral. | |
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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 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, natural gas, 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 extent, heating oil, gasoline 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 and natural gas (“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. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. 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 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) | 3 Months Ended |
Mar. 31, 2014 | |
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 amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply's President and Vice President. | |
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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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. | |
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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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 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 AEP System's market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, 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, Restricted Cash for Securitized Funding 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) | 3 Months Ended |
Mar. 31, 2014 | |
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) | 3 Months Ended |
Mar. 31, 2014 | |
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) | 3 Months Ended | ||||||||||||||
Mar. 31, 2014 | |||||||||||||||
Basic and Diluted EPS Calculations | ' | ||||||||||||||
Three Months Ended March 31, | |||||||||||||||
2014 | 2013 | ||||||||||||||
(in millions, except per share data) | |||||||||||||||
$/share | $/share | ||||||||||||||
Earnings Attributable to AEP Common Shareholders | $ | 560 | $ | 363 | |||||||||||
Weighted Average Number of Basic Shares Outstanding | 487.9 | $ | 1.15 | 485.8 | $ | 0.75 | |||||||||
Weighted Average Dilutive Effect of: | |||||||||||||||
Restricted Stock Units | 0.4 | - | 0.5 | - | |||||||||||
Weighted Average Number of Diluted Shares Outstanding | 488.3 | $ | 1.15 | 486.3 | $ | 0.75 |
Comprehensive_Income_Tables
Comprehensive Income (Tables) | 3 Months Ended | ||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income by Component | ' | ||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 2014 | |||||||||||||||||
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, 2013 | $ | - | $ | -23 | $ | 7 | $ | -99 | $ | -115 | |||||||
Change in Fair Value Recognized in AOCI | -14 | - | - | - | -14 | ||||||||||||
Amounts Reclassified from AOCI | 18 | 1 | - | 1 | 20 | ||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 4 | 1 | - | 1 | 6 | ||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 4 | $ | -22 | $ | 7 | $ | -98 | $ | -109 | |||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 18 | 3 | 1 | - | 22 | ||||||||||||
Amounts Reclassified from AOCI | 2 | 1 | - | 6 | 9 | ||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 20 | 4 | 1 | 6 | 31 | ||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 12 | $ | -26 | $ | 5 | $ | -297 | $ | -306 | |||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in millions) | ||||||||||||||||
Commodity: | |||||||||||||||||
Vertically Integrated Utilities Revenues | $ | - | $ | - | |||||||||||||
Generation & Marketing Revenues | - | -3 | |||||||||||||||
Purchased Electricity for Resale | 31 | 6 | |||||||||||||||
Property, Plant and Equipment | - | - | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -3 | - | |||||||||||||||
Subtotal - Commodity | 28 | 3 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 2 | 2 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 2 | 2 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 30 | 5 | |||||||||||||||
Income Tax (Expense) Credit | 11 | 2 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19 | 3 | |||||||||||||||
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 | - | - | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -5 | -5 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 7 | 14 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2 | 9 | |||||||||||||||
Income Tax (Expense) Credit | 1 | 3 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1 | 6 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 20 | $ | 9 | |||||||||||||
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. | |||||||||||||||||
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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 94 | $ | 3,090 | $ | -233 | $ | 2,951 | |||||||||
Change in Fair Value Recognized in AOCI | 1,583 | - | - | 1,583 | |||||||||||||
Amounts Reclassified from AOCI | -1,590 | 253 | -333 | -1,670 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -7 | 253 | -333 | -87 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 87 | $ | 3,343 | $ | -566 | $ | 2,864 | |||||||||
APCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 794 | -1 | - | 793 | |||||||||||||
Amounts Reclassified from AOCI | 211 | 254 | 358 | 823 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 1,005 | 253 | 358 | 1,616 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 361 | $ | 2,330 | $ | -30,973 | $ | -28,282 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
APCo | |||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 20 | |||||||||||||
Purchased Electricity for Resale | -462 | 57 | |||||||||||||||
Other Operation Expense | -10 | -11 | |||||||||||||||
Maintenance Expense | -20 | -16 | |||||||||||||||
Property, Plant and Equipment | -17 | -14 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -1,937 | 289 | |||||||||||||||
Subtotal - Commodity | -2,446 | 325 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 390 | 390 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 390 | 390 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,056 | 715 | |||||||||||||||
Income Tax (Expense) Credit | -719 | 250 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337 | 465 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -1,282 | -1,282 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 770 | 1,833 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -512 | 551 | |||||||||||||||
Income Tax (Expense) Credit | -179 | 193 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333 | 358 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -1,670 | $ | 823 | |||||||||||||
(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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 46 | $ | -15,976 | $ | 421 | $ | -15,509 | |||||||||
Change in Fair Value Recognized in AOCI | 1,062 | - | - | 1,062 | |||||||||||||
Amounts Reclassified from AOCI | -1,047 | 410 | 43 | -594 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 15 | 410 | 43 | 468 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | 61 | $ | -15,566 | $ | 464 | $ | -15,041 | |||||||||
I&M | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 532 | 2,249 | - | 2,781 | |||||||||||||
Amounts Reclassified from AOCI | 150 | 192 | 176 | 518 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 682 | 2,441 | 176 | 3,299 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 236 | $ | -17,206 | $ | -8,614 | $ | -25,584 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
I&M | |||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 52 | |||||||||||||
Purchased Electricity for Resale | -717 | 149 | |||||||||||||||
Other Operation Expense | -7 | -7 | |||||||||||||||
Maintenance Expense | -7 | -7 | |||||||||||||||
Property, Plant and Equipment | -10 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -870 | 50 | |||||||||||||||
Subtotal - Commodity | -1,611 | 230 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 631 | 296 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 631 | 296 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -980 | 526 | |||||||||||||||
Income Tax (Expense) Credit | -343 | 184 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637 | 342 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -199 | -199 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 265 | 469 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 66 | 270 | |||||||||||||||
Income Tax (Expense) Credit | 23 | 94 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43 | 176 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -594 | $ | 518 | |||||||||||||
(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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 105 | $ | 6,974 | $ | - | $ | 7,079 | |||||||||
Change in Fair Value Recognized in AOCI | - | - | - | - | |||||||||||||
Amounts Reclassified from AOCI | -105 | -343 | - | -448 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -105 | -343 | - | -448 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | 6,631 | $ | - | $ | 6,631 | |||||||||
OPCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | |||||||||
Change in Fair Value Recognized in AOCI | 1,102 | - | - | 1,102 | |||||||||||||
Amounts Reclassified from AOCI | 304 | -340 | 3,269 | 3,233 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 1,406 | -340 | 3,269 | 4,335 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 494 | $ | 7,755 | $ | -169,639 | $ | -161,390 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
OPCo | |||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Electric Generation, Transmission and Distribution Revenues | $ | - | $ | 134 | |||||||||||||
Purchased Electricity for Resale | - | 382 | |||||||||||||||
Other Operation Expense | -11 | -18 | |||||||||||||||
Maintenance Expense | -11 | -12 | |||||||||||||||
Property, Plant and Equipment | -18 | -19 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -122 | - | |||||||||||||||
Subtotal - Commodity | -162 | 467 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Depreciation and Amortization Expense | -3 | 2 | |||||||||||||||
Interest Expense | -524 | -524 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -527 | -522 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -689 | -55 | |||||||||||||||
Income Tax (Expense) Credit | -241 | -19 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448 | -36 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | - | -1,468 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | - | 6,497 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | - | 5,029 | |||||||||||||||
Income Tax (Expense) Credit | - | 1,760 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | - | 3,269 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -448 | $ | 3,233 | |||||||||||||
(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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | |||||||||||||||||
Commodity | Foreign Currency | Total | |||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 57 | $ | 5,701 | $ | 5,758 | |||||||||||
Change in Fair Value Recognized in AOCI | - | - | - | ||||||||||||||
Amounts Reclassified from AOCI | -57 | -189 | -246 | ||||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -57 | -189 | -246 | ||||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | 5,512 | $ | 5,512 | |||||||||||
PSO | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 36 | - | 36 | ||||||||||||||
Amounts Reclassified from AOCI | -13 | -190 | -203 | ||||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 23 | -190 | -167 | ||||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 44 | $ | 6,270 | $ | 6,314 | |||||||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
PSO | |||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Other Operation Expense | $ | -8 | $ | -9 | |||||||||||||
Maintenance Expense | -9 | -4 | |||||||||||||||
Property, Plant and Equipment | -13 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -58 | - | |||||||||||||||
Subtotal - Commodity | -88 | -20 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | -292 | -292 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | -292 | -292 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -380 | -312 | |||||||||||||||
Income Tax (Expense) Credit | -134 | -109 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | -246 | $ | -203 | |||||||||||||
(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 March 31, 2014 | |||||||||||||||||
Cash Flow Hedges | |||||||||||||||||
Interest Rate and | Pension | ||||||||||||||||
Commodity | Foreign Currency | and OPEB | Total | ||||||||||||||
(in thousands) | |||||||||||||||||
Balance in AOCI as of December 31, 2013 | $ | 66 | $ | -13,304 | $ | 4,794 | $ | -8,444 | |||||||||
Change in Fair Value Recognized in AOCI | - | - | - | - | |||||||||||||
Amounts Reclassified from AOCI | -66 | 568 | -234 | 268 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | -66 | 568 | -234 | 268 | |||||||||||||
Balance in AOCI as of March 31, 2014 | $ | - | $ | -12,736 | $ | 4,560 | $ | -8,176 | |||||||||
SWEPCo | |||||||||||||||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | |||||||||||||||||
For the Three Months Ended March 31, 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 | 44 | - | - | 44 | |||||||||||||
Amounts Reclassified from AOCI | -15 | 567 | -63 | 489 | |||||||||||||
Net Current Period Other | |||||||||||||||||
Comprehensive Income | 29 | 567 | -63 | 533 | |||||||||||||
Balance in AOCI as of March 31, 2013 | $ | 51 | $ | -15,004 | $ | -2,374 | $ | -17,327 | |||||||||
Reclassifications from Accumulated Other Comprehensive Income | ' | ||||||||||||||||
SWEPCo | |||||||||||||||||
Reclassifications from Accumulated Other Comprehensive Income (Loss) | |||||||||||||||||
For the Three Months Ended March 31, 2014 and 2013 | |||||||||||||||||
Amount of (Gain) Loss | |||||||||||||||||
Reclassified from AOCI | |||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||
2014 | 2013 | ||||||||||||||||
Gains and Losses on Cash Flow Hedges | (in thousands) | ||||||||||||||||
Commodity: | |||||||||||||||||
Other Operation Expense | $ | -13 | $ | -10 | |||||||||||||
Maintenance Expense | -10 | -6 | |||||||||||||||
Property, Plant and Equipment | -11 | -7 | |||||||||||||||
Regulatory Assets/(Liabilities), Net (a) | -67 | - | |||||||||||||||
Subtotal - Commodity | -101 | -23 | |||||||||||||||
Interest Rate and Foreign Currency: | |||||||||||||||||
Interest Expense | 872 | 872 | |||||||||||||||
Subtotal - Interest Rate and Foreign Currency | 872 | 872 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 771 | 849 | |||||||||||||||
Income Tax (Expense) Credit | 269 | 297 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502 | 552 | |||||||||||||||
Pension and OPEB | |||||||||||||||||
Amortization of Prior Service Cost (Credit) | -478 | -445 | |||||||||||||||
Amortization of Actuarial (Gains)/Losses | 118 | 348 | |||||||||||||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -360 | -97 | |||||||||||||||
Income Tax (Expense) Credit | -126 | -34 | |||||||||||||||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234 | -63 | |||||||||||||||
Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit | $ | 268 | $ | 489 | |||||||||||||
(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) | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in millions) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Storm Related Costs | $ | 21 | $ | 22 | ||||||
Ohio Economic Development Rider | - | 14 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | - | 4 | ||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | 104 | 161 | ||||||||
Indiana Under-Recovered Capacity Costs | 28 | 22 | ||||||||
IGCC Pre-Construction Costs | 21 | - | ||||||||
Expanded Net Energy Charge - Coal Inventory | 19 | 21 | ||||||||
Mountaineer Carbon Capture and Storage Product Validation Facility | 13 | 13 | ||||||||
Ormet Special Rate Recovery Mechanism | 10 | 36 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 34 | 37 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 250 | $ | 330 | ||||||
Appalachian Power Co [Member] | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
APCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
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 | $ | 65,206 | ||||||
IGCC Pre-Construction Costs | 20,528 | - | ||||||||
Expanded Net Energy Charge - Coal Inventory | 18,818 | 20,528 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Product Validation Facility | 13,264 | 13,264 | ||||||||
Virginia Demand Response Program Costs | 5,897 | 5,012 | ||||||||
Transmission Agreement Phase-In | 3,450 | 3,313 | ||||||||
Virginia Environmental Rate Adjustment Clause | 1,941 | 2,440 | ||||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,287 | 1,287 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 513 | 168 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 130,904 | $ | 111,218 | ||||||
Indiana Michigan Power Co [Member] | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
I&M | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Indiana Under-Recovered Capacity Costs | $ | 28,149 | $ | 21,945 | ||||||
Cook Plant Turbine | 4,238 | 3,452 | ||||||||
Stranded Costs on Abandoned Plants | 3,897 | 3,896 | ||||||||
Storm Related Costs | 751 | 1,836 | ||||||||
Indiana Deferred Cook Plant Life Cycle Management Project Costs | - | 4,093 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 694 | 164 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 37,729 | $ | 35,386 | ||||||
Ohio Power Co [Member] | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
OPCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Earning a Return | ||||||||||
Economic Development Rider | $ | - | $ | 13,854 | ||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Ormet Special Rate Recovery Mechanism | 10,483 | 35,631 | ||||||||
Storm Related Costs | 1,635 | 57,589 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 12,118 | $ | 107,074 | ||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
PSO | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Storm Related Costs | $ | 19,093 | $ | 18,743 | ||||||
Other Regulatory Assets Not Yet Being Recovered | 1,079 | 845 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 20,172 | $ | 19,588 | ||||||
Southwestern Electric Power Co [Member] | ' | |||||||||
Regulatory Assets Not Yet Being Recovered | ' | |||||||||
SWEPCo | ||||||||||
March 31, | December 31, | |||||||||
2014 | 2013 | |||||||||
Noncurrent Regulatory Assets | (in thousands) | |||||||||
Regulatory assets not yet being recovered pending future proceedings: | ||||||||||
Regulatory Assets Currently Not Earning a Return | ||||||||||
Rate Case Expenses | $ | 7,930 | $ | 7,934 | ||||||
Mountaineer Carbon Capture and Storage | ||||||||||
Commercial Scale Facility | 1,143 | 1,143 | ||||||||
Other Regulatory Assets Not Yet Being Recovered | 2,025 | 1,951 | ||||||||
Total Regulatory Assets Not Yet Being Recovered | $ | 11,098 | $ | 11,028 |
Commitments_Guarantees_and_Con1
Commitments, Guarantees and Contingencies (Tables) | 3 Months Ended | |||||||||
Mar. 31, 2014 | ||||||||||
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 2016 to March 2017 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
Maximum Potential Loss on Master Lease Agreements | ' | |||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Indiana Michigan Power Co [Member] | ' | |||||||||
Maximum Future Payments of Letters of Credit | ' | |||||||||
Company | Amount | Maturity | ||||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-15 | |||||||
OPCo | 3,081 | Jun-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 2016 to March 2017 | |||||
I&M | 77,000 | 77,886 | Mar-15 | |||||||
Maximum Potential Loss on Master Lease Agreements | ' | |||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Ohio Power Co [Member] | ' | |||||||||
Maximum Future Payments of Letters of Credit | ' | |||||||||
Company | Amount | Maturity | ||||||||
(in thousands) | ||||||||||
I&M | $ | 150 | Mar-15 | |||||||
OPCo | 3,081 | Jun-14 | ||||||||
Maximum Potential Loss on Master Lease Agreements | ' | |||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||
Maximum Potential Loss on Master Lease Agreements | ' | |||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 | |||||||||
Southwestern Electric Power Co [Member] | ' | |||||||||
Maximum Potential Loss on Master Lease Agreements | ' | |||||||||
Maximum | ||||||||||
Company | Potential Loss | |||||||||
(in thousands) | ||||||||||
APCo | $ | 3,772 | ||||||||
I&M | 2,580 | |||||||||
OPCo | 4,384 | |||||||||
PSO | 1,347 | |||||||||
SWEPCo | 2,486 |
Benefit_Plans_Tables
Benefit Plans (Tables) | 3 Months Ended | |||||||||||
Mar. 31, 2014 | ||||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in millions) | ||||||||||||
Service Cost | $ | 18 | $ | 17 | $ | 4 | $ | 6 | ||||
Interest Cost | 55 | 50 | 17 | 18 | ||||||||
Expected Return on Plan Assets | -66 | -69 | -28 | -27 | ||||||||
Amortization of Prior Service Cost (Credit) | 1 | 1 | -17 | -17 | ||||||||
Amortization of Net Actuarial Loss | 31 | 46 | 5 | 16 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 39 | $ | 45 | $ | -19 | $ | -4 | ||||
Appalachian Power Co [Member] | ' | |||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
APCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,759 | $ | 1,543 | $ | 362 | $ | 641 | ||||
Interest Cost | 7,406 | 6,916 | 3,197 | 3,363 | ||||||||
Expected Return on Plan Assets | -8,482 | -9,260 | -4,633 | -4,536 | ||||||||
Amortization of Prior Service Cost (Credit) | 50 | 49 | -2,513 | -2,512 | ||||||||
Amortization of Net Actuarial Loss | 4,148 | 6,256 | 1,146 | 3,062 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 4,881 | $ | 5,504 | $ | -2,441 | $ | 18 | ||||
Indiana Michigan Power Co [Member] | ' | |||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
I&M | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 2,517 | $ | 2,184 | $ | 487 | $ | 805 | ||||
Interest Cost | 6,573 | 6,025 | 1,909 | 2,055 | ||||||||
Expected Return on Plan Assets | -7,748 | -8,207 | -3,364 | -3,296 | ||||||||
Amortization of Prior Service Cost (Credit) | 49 | 49 | -2,355 | -2,355 | ||||||||
Amortization of Net Actuarial Loss | 3,646 | 5,422 | 592 | 1,882 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 5,037 | $ | 5,473 | $ | -2,731 | $ | -909 | ||||
Ohio Power Co [Member] | ' | |||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
OPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,285 | $ | 2,372 | $ | 256 | $ | 1,300 | ||||
Interest Cost | 5,526 | 10,292 | 1,901 | 4,447 | ||||||||
Expected Return on Plan Assets | -6,607 | -15,141 | -3,380 | -6,238 | ||||||||
Amortization of Prior Service Cost (Credit) | 39 | 71 | -1,731 | -3,231 | ||||||||
Amortization of Net Actuarial Loss | 3,106 | 9,309 | 595 | 4,041 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 3,349 | $ | 6,903 | $ | -2,359 | $ | 319 | ||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
PSO | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,302 | $ | 1,391 | $ | 210 | $ | 343 | ||||
Interest Cost | 3,014 | 2,748 | 893 | 948 | ||||||||
Expected Return on Plan Assets | -3,651 | -3,918 | -1,575 | -1,522 | ||||||||
Amortization of Prior Service Cost (Credit) | 74 | 74 | -1,072 | -1,072 | ||||||||
Amortization of Net Actuarial Loss | 1,688 | 2,461 | 277 | 869 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,427 | $ | 2,756 | $ | -1,267 | $ | -434 | ||||
Southwestern Electric Power Co [Member] | ' | |||||||||||
Components of Net Periodic Benefit Cost | ' | |||||||||||
SWEPCo | ||||||||||||
Other Postretirement | ||||||||||||
Pension Plans | Benefit Plans | |||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||
2014 | 2013 | 2014 | 2013 | |||||||||
(in thousands) | ||||||||||||
Service Cost | $ | 1,655 | $ | 1,753 | $ | 253 | $ | 423 | ||||
Interest Cost | 3,163 | 2,864 | 998 | 1,075 | ||||||||
Expected Return on Plan Assets | -3,857 | -4,127 | -1,754 | -1,720 | ||||||||
Amortization of Prior Service Cost (Credit) | 87 | 87 | -1,289 | -1,288 | ||||||||
Amortization of Net Actuarial Loss | 1,761 | 2,553 | 309 | 982 | ||||||||
Net Periodic Benefit Cost (Credit) | $ | 2,809 | $ | 3,130 | $ | -1,483 | $ | -528 |
Business_Segments_Tables
Business Segments (Tables) | 3 Months Ended | |||||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||||
Business Segments (Tables) [Abstract] | ' | |||||||||||||||||||||||||||
Reportable Segment Information | ' | |||||||||||||||||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | ||||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Reconciling | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | Adjustments | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Three Months Ended March 31, 2014 | ||||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||||
External Customers | $ | 2,549 | (b) | $ | 1,161 | $ | 12 | $ | 821 | (b) | $ | 146 | $ | 10 | $ | -51 | (c) | $ | 4,648 | |||||||||
Other Operating Segments | 37 | (b) | 54 | 16 | 430 | (b) | 19 | 16 | -572 | - | ||||||||||||||||||
Total Revenues | $ | 2,586 | $ | 1,215 | $ | 28 | $ | 1,251 | $ | 165 | $ | 26 | $ | -623 | $ | 4,648 | ||||||||||||
Net Income (Loss) | $ | 279 | $ | 97 | $ | 24 | $ | 163 | $ | 3 | $ | -5 | $ | - | $ | 561 | ||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | ||||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Reconciling | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | Adjustments | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Three Months Ended March 31, 2013 | ||||||||||||||||||||||||||||
Revenues from: | ||||||||||||||||||||||||||||
External Customers | $ | 2,356 | $ | 1,090 | $ | 3 | $ | 258 | $ | 128 | $ | 5 | $ | -14 | (c) | $ | 3,826 | |||||||||||
Other Operating Segments | 159 | 44 | 5 | 662 | 5 | 13 | -888 | - | ||||||||||||||||||||
Total Revenues | $ | 2,515 | $ | 1,134 | $ | 8 | $ | 920 | $ | 133 | $ | 18 | $ | -902 | $ | 3,826 | ||||||||||||
Net Income (Loss) | $ | 181 | $ | 87 | $ | 12 | $ | 85 | $ | -2 | $ | 1 | $ | - | $ | 364 | ||||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | Reconciling | |||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Adjustments | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | (d) | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
31-Mar-14 | ||||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 37,923 | $ | 12,339 | $ | 1,842 | $ | 8,302 | $ | 639 | $ | 321 | $ | -272 | $ | 61,094 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||||
Amortization | 12,424 | 3,382 | 13 | 3,460 | 197 | 176 | -88 | 19,564 | ||||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||||
Equipment - Net | $ | 25,499 | $ | 8,957 | $ | 1,829 | $ | 4,842 | $ | 442 | $ | 145 | $ | -184 | $ | 41,530 | ||||||||||||
Total Assets | $ | 32,997 | $ | 13,899 | $ | 2,460 | $ | 6,354 | $ | 659 | $ | 20,275 | $ | -19,606 | (e) | $ | 57,038 | |||||||||||
Transmission | ||||||||||||||||||||||||||||
Vertically | and | AEP | Generation | Corporate | Reconciling | |||||||||||||||||||||||
Integrated | Distribution | Transmission | & | AEP River | and Other | Adjustments | ||||||||||||||||||||||
Utilities | Utilities | Holdco | Marketing | Operations | (a) | (d) | Consolidated | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||||
Total Property, Plant and Equipment | $ | 37,545 | $ | 12,143 | $ | 1,636 | $ | 8,277 | $ | 638 | $ | 315 | $ | -269 | $ | 60,285 | ||||||||||||
Accumulated Depreciation and | ||||||||||||||||||||||||||||
Amortization | 12,250 | 3,342 | 10 | 3,409 | 189 | 173 | -85 | 19,288 | ||||||||||||||||||||
Total Property, Plant and | ||||||||||||||||||||||||||||
Equipment - Net | $ | 25,295 | $ | 8,801 | $ | 1,626 | $ | 4,868 | $ | 449 | $ | 142 | $ | -184 | $ | 40,997 | ||||||||||||
Total Assets | $ | 32,791 | $ | 14,165 | $ | 2,245 | $ | 6,426 | $ | 673 | $ | 19,645 | $ | -19,531 | (e) | $ | 56,414 | |||||||||||
(a) Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | ||||||||||||||||||||||||||||
(b) Includes the impact of the corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. | ||||||||||||||||||||||||||||
(c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation. | ||||||||||||||||||||||||||||
(d) Includes eliminations due to an intercompany capital lease. | ||||||||||||||||||||||||||||
(e) 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) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
Volume | |||||||||||||||||||||
March 31, | December 31, | Unit of | |||||||||||||||||||
2014 | 2013 | Measure | |||||||||||||||||||
Primary Risk Exposure | (in millions) | ||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | 320 | 406 | MWhs | ||||||||||||||||||
Coal | 4 | 4 | Tons | ||||||||||||||||||
Natural Gas | 123 | 127 | MMBtus | ||||||||||||||||||
Heating Oil and Gasoline | 4 | 6 | Gallons | ||||||||||||||||||
Interest Rate | $ | 192 | $ | 191 | USD | ||||||||||||||||
Interest Rate and Foreign Currency | $ | 819 | $ | 820 | USD | ||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 442 | $ | 23 | $ | 4 | $ | 469 | $ | -344 | $ | 125 | |||||||||
Long-term Risk Management Assets | 342 | 5 | - | 347 | -81 | 266 | |||||||||||||||
Total Assets | 784 | 28 | 4 | 816 | -425 | 391 | |||||||||||||||
Current Risk Management Liabilities | 384 | 16 | 1 | 401 | -341 | 60 | |||||||||||||||
Long-term Risk Management Liabilities | 205 | 4 | 13 | 222 | -85 | 137 | |||||||||||||||
Total Liabilities | 589 | 20 | 14 | 623 | -426 | 197 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 195 | $ | 8 | $ | -10 | $ | 193 | $ | 1 | $ | 194 | |||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 347 | $ | 12 | $ | 4 | $ | 363 | $ | -203 | $ | 160 | |||||||||
Long-term Risk Management Assets | 368 | 3 | - | 371 | -74 | 297 | |||||||||||||||
Total Assets | 715 | 15 | 4 | 734 | -277 | 457 | |||||||||||||||
Current Risk Management Liabilities | 292 | 11 | 1 | 304 | -214 | 90 | |||||||||||||||
Long-term Risk Management Liabilities | 237 | 3 | 15 | 255 | -78 | 177 | |||||||||||||||
Total Liabilities | 529 | 14 | 16 | 559 | -292 | 267 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 186 | $ | 1 | $ | -12 | $ | 175 | $ | 15 | $ | 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 Months Ended March 31, 2014 and 2013 | |||||||||||||||||||||
Location of Gain (Loss) | 2014 | 2013 | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Vertically Integrated Utilities Revenues | $ | 18 | $ | 6 | |||||||||||||||||
Generation & Marketing Revenues | 32 | 16 | |||||||||||||||||||
Regulatory Assets (a) | - | 2 | |||||||||||||||||||
Regulatory Liabilities (a) | 89 | -6 | |||||||||||||||||||
Total Gain on Risk Management Contracts | $ | 139 | $ | 18 | |||||||||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 13 | $ | - | $ | 13 | |||||||||||||||
Hedging Liabilities (a) | 5 | 2 | 7 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | 4 | -22 | -18 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | 3 | -4 | -1 | ||||||||||||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Commodity | Currency | Total | |||||||||||||||||||
(in millions) | |||||||||||||||||||||
Hedging Assets (a) | $ | 7 | $ | - | $ | 7 | |||||||||||||||
Hedging Liabilities (a) | 6 | 2 | 8 | ||||||||||||||||||
AOCI Gain (Loss) Net of Tax | - | -23 | -23 | ||||||||||||||||||
Portion Expected to be Reclassified to Net | |||||||||||||||||||||
Income During the Next Twelve Months | - | -4 | -4 | ||||||||||||||||||
(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 | ' | ||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | $ | 2 | $ | 3 | |||||||||||||||||
Amount of Collateral AEP Subsidiaries Would Have Been | |||||||||||||||||||||
Required to Post | 144 | 33 | |||||||||||||||||||
Amount Attributable to RTO and ISO Activities | 38 | 28 | |||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
March 31, | December 31, | ||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual | |||||||||||||||||||||
Netting Arrangements | $ | 225 | $ | 293 | |||||||||||||||||
Amount of Cash Collateral Posted | - | 1 | |||||||||||||||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 177 | 235 | |||||||||||||||||||
Appalachian Power Co [Member] | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 34,483 | $ | 224 | $ | - | $ | 34,707 | $ | -18,735 | $ | 15,972 | |||||||||
Long-term Risk Management Assets | 17,304 | - | - | 17,304 | -3,291 | 14,013 | |||||||||||||||
Total Assets | 51,787 | 224 | - | 52,011 | -22,026 | 29,985 | |||||||||||||||
Current Risk Management Liabilities | 24,273 | 90 | - | 24,363 | -19,727 | 4,636 | |||||||||||||||
Long-term Risk Management Liabilities | 11,558 | - | - | 11,558 | -3,629 | 7,929 | |||||||||||||||
Total Liabilities | 35,831 | 90 | - | 35,921 | -23,356 | 12,565 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 15,956 | $ | 134 | $ | - | $ | 16,090 | $ | 1,330 | $ | 17,420 | |||||||||
APCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 46,431 | $ | 389 | $ | - | $ | 46,820 | $ | -25,649 | $ | 21,171 | |||||||||
Long-term Risk Management Assets | 20,948 | - | - | 20,948 | -4,000 | 16,948 | |||||||||||||||
Total Assets | 67,379 | 389 | - | 67,768 | -29,649 | 38,119 | |||||||||||||||
Current Risk Management Liabilities | 37,010 | 313 | - | 37,323 | -28,431 | 8,892 | |||||||||||||||
Long-term Risk Management Liabilities | 14,452 | - | - | 14,452 | -4,211 | 10,241 | |||||||||||||||
Total Liabilities | 51,462 | 313 | - | 51,775 | -32,642 | 19,133 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 15,917 | $ | 76 | $ | - | $ | 15,993 | $ | 2,993 | $ | 18,986 | |||||||||
(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 March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
Indiana Michigan Power Co [Member] | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 26,273 | $ | 152 | $ | - | $ | 26,425 | $ | -13,867 | $ | 12,558 | |||||||||
Long-term Risk Management Assets | 11,737 | - | - | 11,737 | -2,232 | 9,505 | |||||||||||||||
Total Assets | 38,010 | 152 | - | 38,162 | -16,099 | 22,063 | |||||||||||||||
Current Risk Management Liabilities | 18,614 | 61 | - | 18,675 | -14,541 | 4,134 | |||||||||||||||
Long-term Risk Management Liabilities | 7,839 | - | - | 7,839 | -2,461 | 5,378 | |||||||||||||||
Total Liabilities | 26,453 | 61 | - | 26,514 | -17,002 | 9,512 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 11,557 | $ | 91 | $ | - | $ | 11,648 | $ | 903 | $ | 12,551 | |||||||||
I&M | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 33,229 | $ | 234 | $ | - | $ | 33,463 | $ | -18,075 | $ | 15,388 | |||||||||
Long-term Risk Management Assets | 14,208 | - | - | 14,208 | -2,713 | 11,495 | |||||||||||||||
Total Assets | 47,437 | 234 | - | 47,671 | -20,788 | 26,883 | |||||||||||||||
Current Risk Management Liabilities | 26,779 | 212 | - | 26,991 | -19,962 | 7,029 | |||||||||||||||
Long-term Risk Management Liabilities | 9,802 | - | - | 9,802 | -2,856 | 6,946 | |||||||||||||||
Total Liabilities | 36,581 | 212 | - | 36,793 | -22,818 | 13,975 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 10,856 | $ | 22 | $ | - | $ | 10,878 | $ | 2,030 | $ | 12,908 | |||||||||
(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 March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
Ohio Power Co [Member] | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 4,066 | $ | - | $ | - | $ | 4,066 | $ | -86 | $ | 3,980 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 4,066 | - | - | 4,066 | -86 | 3,980 | |||||||||||||||
Current Risk Management Liabilities | 83 | - | - | 83 | -83 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 83 | - | - | 83 | -83 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 3,983 | $ | - | $ | - | $ | 3,983 | $ | -3 | $ | 3,980 | |||||||||
OPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 3,269 | $ | 162 | $ | - | $ | 3,431 | $ | -349 | $ | 3,082 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 3,269 | 162 | - | 3,431 | -349 | 3,082 | |||||||||||||||
Current Risk Management Liabilities | 349 | - | - | 349 | -349 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 349 | - | - | 349 | -349 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 2,920 | $ | 162 | $ | - | $ | 3,082 | $ | - | $ | 3,082 | |||||||||
(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 March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 1,403 | $ | - | $ | - | $ | 1,403 | $ | -54 | $ | 1,349 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,403 | - | - | 1,403 | -54 | 1,349 | |||||||||||||||
Current Risk Management Liabilities | 136 | - | - | 136 | -53 | 83 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 136 | - | - | 136 | -53 | 83 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,267 | $ | - | $ | - | $ | 1,267 | $ | -1 | $ | 1,266 | |||||||||
PSO | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 1,078 | $ | 84 | $ | - | $ | 1,162 | $ | 5 | $ | 1,167 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,078 | 84 | - | 1,162 | 5 | 1,167 | |||||||||||||||
Current Risk Management Liabilities | 81 | - | - | 81 | 4 | 85 | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 81 | - | - | 81 | 4 | 85 | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 997 | $ | 84 | $ | - | $ | 1,081 | $ | 1 | $ | 1,082 | |||||||||
(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 March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 | ||||||||||||||||||
Southwestern Electric Power Co [Member] | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | ' | ||||||||||||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 29,680 | 19,636 | 12,108 | 9,251 | 11,716 | |||||||||||||||
Coal | Tons | 186 | 2,666 | - | 750 | 1,292 | |||||||||||||||
Natural Gas | MMBtus | 1,934 | 1,312 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 792 | 379 | 806 | 446 | 508 | |||||||||||||||
Interest Rate | USD | $ | 10,877 | $ | 7,378 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Notional Volume of Derivative Instruments | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Primary Risk | Unit of | ||||||||||||||||||||
Exposure | Measure | APCo | I&M | OPCo | PSO | SWEPCo | |||||||||||||||
(in thousands) | |||||||||||||||||||||
Commodity: | |||||||||||||||||||||
Power | MWhs | 48,995 | 33,231 | 34,843 | 13,469 | 17,057 | |||||||||||||||
Coal | Tons | 31 | 3,389 | - | 1,013 | 1,692 | |||||||||||||||
Natural Gas | MMBtus | 2,477 | 1,680 | - | - | - | |||||||||||||||
Heating Oil and | |||||||||||||||||||||
Gasoline | Gallons | 1,089 | 521 | 1,108 | 614 | 699 | |||||||||||||||
Interest Rate | USD | $ | 12,720 | $ | 8,627 | $ | - | $ | - | $ | - | ||||||||||
Interest Rate and | |||||||||||||||||||||
Foreign Currency | USD | $ | - | $ | - | $ | - | $ | - | $ | - | ||||||||||
Cash Collateral Netting | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 32 | $ | 1,362 | $ | - | $ | 2,993 | |||||||||||||
I&M | 21 | 924 | - | 2,030 | |||||||||||||||||
OPCo | 3 | - | - | - | |||||||||||||||||
PSO | 1 | - | - | 1 | |||||||||||||||||
SWEPCo | 2 | - | - | 3 | |||||||||||||||||
Fair Value of Derivative Instruments | ' | ||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 2,080 | $ | - | $ | - | $ | 2,080 | $ | -173 | $ | 1,907 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 2,080 | - | - | 2,080 | -173 | 1,907 | |||||||||||||||
Current Risk Management Liabilities | 171 | - | - | 171 | -171 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 171 | - | - | 171 | -171 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,909 | $ | - | $ | - | $ | 1,909 | $ | -2 | $ | 1,907 | |||||||||
SWEPCo | |||||||||||||||||||||
Fair Value of Derivative Instruments | |||||||||||||||||||||
31-Dec-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 | $ | 1,233 | $ | 97 | $ | - | $ | 1,330 | $ | -151 | $ | 1,179 | |||||||||
Long-term Risk Management Assets | - | - | - | - | - | - | |||||||||||||||
Total Assets | 1,233 | 97 | - | 1,330 | -151 | 1,179 | |||||||||||||||
Current Risk Management Liabilities | 154 | - | - | 154 | -154 | - | |||||||||||||||
Long-term Risk Management Liabilities | - | - | - | - | - | - | |||||||||||||||
Total Liabilities | 154 | - | - | 154 | -154 | - | |||||||||||||||
Total MTM Derivative Contract Net | |||||||||||||||||||||
Assets (Liabilities) | $ | 1,079 | $ | 97 | $ | - | $ | 1,176 | $ | 3 | $ | 1,179 | |||||||||
(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 March 31, 2014 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 4,847 | $ | 6,156 | $ | - | $ | 64 | $ | 23 | |||||||||||
Sales to AEP Affiliates | - | -221 | - | 221 | - | ||||||||||||||||
Regulatory Assets (a) | 4 | - | - | 2 | 3 | ||||||||||||||||
Regulatory Liabilities (a) | 32,332 | 18,317 | 35,099 | 480 | 1,330 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 37,183 | $ | 24,252 | $ | 35,099 | $ | 767 | $ | 1,356 | |||||||||||
Amount of Gain (Loss) Recognized on | |||||||||||||||||||||
Risk Management Contracts | |||||||||||||||||||||
For the Three Months Ended March 31, 2013 | |||||||||||||||||||||
Location of Gain (Loss) | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Electric Generation, Transmission and | |||||||||||||||||||||
Distribution Revenues | $ | 679 | $ | 4,947 | $ | 1,714 | $ | 47 | $ | 28 | |||||||||||
Regulatory Assets (a) | - | 486 | -1,205 | 2,010 | 271 | ||||||||||||||||
Regulatory Liabilities (a) | -466 | -5,182 | - | 1 | 96 | ||||||||||||||||
Total Gain on Risk Management | |||||||||||||||||||||
Contracts | $ | 213 | $ | 251 | $ | 509 | $ | 2,058 | $ | 395 | |||||||||||
(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 | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 209 | $ | - | $ | 75 | $ | - | $ | 87 | $ | 3,343 | |||||||||
I&M | 142 | - | 51 | - | 61 | -15,566 | |||||||||||||||
OPCo | - | - | - | - | - | 6,631 | |||||||||||||||
PSO | - | - | - | - | - | 5,512 | |||||||||||||||
SWEPCo | - | - | - | - | - | -12,736 | |||||||||||||||
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 | $ | 87 | $ | -682 | 2 | ||||||||||||||||
I&M | 61 | -1,426 | 2 | ||||||||||||||||||
OPCo | - | 1,372 | - | ||||||||||||||||||
PSO | - | 759 | - | ||||||||||||||||||
SWEPCo | - | -2,267 | - | ||||||||||||||||||
Impact of Cash Flow Hedges on the Registrant Subsidiaries’ | |||||||||||||||||||||
Condensed Balance Sheets | |||||||||||||||||||||
31-Dec-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 | $ | 363 | $ | - | $ | 287 | $ | - | $ | 94 | $ | 3,090 | |||||||||
I&M | 216 | - | 194 | - | 46 | -15,976 | |||||||||||||||
OPCo | 162 | - | - | - | 105 | 6,974 | |||||||||||||||
PSO | 84 | - | - | - | 57 | 5,701 | |||||||||||||||
SWEPCo | 97 | - | - | - | 66 | -13,304 | |||||||||||||||
Expected to be Reclassified to | |||||||||||||||||||||
Net Income During the Next | |||||||||||||||||||||
Twelve Months | |||||||||||||||||||||
Interest Rate | |||||||||||||||||||||
and Foreign | |||||||||||||||||||||
Company | Commodity | Currency | |||||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 94 | $ | -806 | |||||||||||||||||
I&M | 46 | -1,568 | |||||||||||||||||||
OPCo | 105 | 1,363 | |||||||||||||||||||
PSO | 57 | 759 | |||||||||||||||||||
SWEPCo | 66 | -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 | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 285 | $ | 5,254 | $ | 4,774 | |||||||||||||||
I&M | 190 | 3,560 | 3,238 | ||||||||||||||||||
OPCo | 78 | - | - | ||||||||||||||||||
PSO | 132 | 4,156 | - | ||||||||||||||||||
SWEPCo | 167 | 145 | - | ||||||||||||||||||
31-Dec-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 | $ | 575 | $ | 2,747 | $ | 2,539 | |||||||||||||||
I&M | 390 | 1,863 | 1,722 | ||||||||||||||||||
OPCo | 349 | - | - | ||||||||||||||||||
PSO | - | 2,930 | 410 | ||||||||||||||||||
SWEPCo | - | 713 | 519 | ||||||||||||||||||
Liabilities Subject to Cross Default Provisions | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
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 | $ | 16,375 | $ | - | $ | 12,865 | |||||||||||||||
I&M | 11,107 | - | 8,726 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | - | - | - | ||||||||||||||||||
SWEPCo | - | - | - | ||||||||||||||||||
31-Dec-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 | $ | 19,648 | $ | - | $ | 18,568 | |||||||||||||||
I&M | 13,326 | - | 12,594 | ||||||||||||||||||
OPCo | - | - | - | ||||||||||||||||||
PSO | 3 | - | 3 | ||||||||||||||||||
SWEPCo | 3 | - | 3 |
Fair_Value_Measurements_Tables
Fair Value Measurements (Tables) | 3 Months Ended | ||||||||||||||||||||
Mar. 31, 2014 | |||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Book Value | Fair Value | Book Value | Fair Value | ||||||||||||||||||
(in millions) | |||||||||||||||||||||
Long-term Debt | $ | 18,087 | $ | 19,738 | $ | 18,377 | $ | 19,672 | |||||||||||||
Other Temporary Investments | ' | ||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 206 | $ | - | $ | - | $ | 206 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | 80 | |||||||||||||||||
Equity Securities - Mutual Funds | 13 | 11 | - | 24 | |||||||||||||||||
Total Other Temporary Investments | $ | 299 | $ | 11 | $ | - | $ | 310 | |||||||||||||
31-Dec-13 | |||||||||||||||||||||
Gross | Gross | Estimated | |||||||||||||||||||
Unrealized | Unrealized | Fair | |||||||||||||||||||
Other Temporary Investments | Cost | Gains | Losses | Value | |||||||||||||||||
(in millions) | |||||||||||||||||||||
Restricted Cash (a) | $ | 250 | $ | - | $ | - | $ | 250 | |||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | 80 | |||||||||||||||||
Equity Securities - Mutual Funds | 12 | 11 | - | 23 | |||||||||||||||||
Total Other Temporary Investments | $ | 342 | $ | 11 | $ | - | $ | 353 | |||||||||||||
(a) | Primarily represents amounts held for the repayment of debt. | ||||||||||||||||||||
Debt and Equity Securities Within Other Temporary Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | - | $ | - | |||||||||||||||||
Purchases of Investments | 1 | 11 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | - | - | |||||||||||||||||||
Gross Realized Losses on Investment Sales | - | - | |||||||||||||||||||
Nuclear Trust Fund Investments | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 12 | $ | - | $ | - | $ | 19 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 606 | 31 | -4 | 609 | 26 | -4 | |||||||||||||||
Corporate Debt | 43 | 4 | -1 | 37 | 2 | -1 | |||||||||||||||
State and Local Government | 281 | 1 | - | 255 | 1 | - | |||||||||||||||
Subtotal Fixed Income Securities | 930 | 36 | -5 | 901 | 29 | -5 | |||||||||||||||
Equity Securities - Domestic | 1,020 | 514 | -80 | 1,012 | 506 | -82 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,962 | $ | 550 | $ | -85 | $ | 1,932 | $ | 535 | $ | -87 | |||||||||
Securities Activity Within the Decommissioning and SNF Trusts | ' | ||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 148 | $ | 168 | |||||||||||||||||
Purchases of Investments | 164 | 185 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | 8 | 3 | |||||||||||||||||||
Gross Realized Losses on Investment Sales | 1 | 2 | |||||||||||||||||||
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | ' | ||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Within 1 year | $ | 82 | |||||||||||||||||||
1 year – 5 years | 386 | ||||||||||||||||||||
5 years – 10 years | 193 | ||||||||||||||||||||
After 10 years | 269 | ||||||||||||||||||||
Total | $ | 930 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 16 | $ | 1 | $ | - | $ | 275 | $ | 292 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 187 | 7 | - | 12 | 206 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | - | 80 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 24 | - | - | - | 24 | ||||||||||||||||
Total Other Temporary Investments | 291 | 7 | - | 12 | 310 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | 20 | 586 | 128 | -364 | 370 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 21 | 2 | -10 | 13 | ||||||||||||||||
Fair Value Hedges | - | 2 | - | 2 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 4 | 4 | ||||||||||||||||
Total Risk Management Assets | 20 | 609 | 130 | -368 | 391 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 3 | - | - | 9 | 12 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 606 | - | - | 606 | ||||||||||||||||
Corporate Debt | - | 43 | - | - | 43 | ||||||||||||||||
State and Local Government | - | 281 | - | - | 281 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 930 | - | - | 930 | ||||||||||||||||
Equity Securities - Domestic (b) | 1,020 | - | - | - | 1,020 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,023 | 930 | - | 9 | 1,962 | ||||||||||||||||
Total Assets | $ | 1,350 | $ | 1,547 | $ | 130 | $ | -72 | $ | 2,955 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (d) | $ | 30 | $ | 485 | $ | 25 | $ | -362 | $ | 178 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 15 | - | -10 | 5 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 10 | - | 2 | 12 | ||||||||||||||||
Total Risk Management Liabilities | $ | 30 | $ | 512 | $ | 25 | $ | -370 | $ | 197 | |||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in millions) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 16 | $ | 1 | $ | - | $ | 101 | $ | 118 | |||||||||||
Other Temporary Investments | |||||||||||||||||||||
Restricted Cash (a) | 231 | 8 | - | 11 | 250 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
Mutual Funds | 80 | - | - | - | 80 | ||||||||||||||||
Equity Securities - Mutual Funds (b) | 23 | - | - | - | 23 | ||||||||||||||||
Total Other Temporary Investments | 334 | 8 | - | 11 | 353 | ||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | 22 | 549 | 142 | -273 | 440 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 15 | - | -8 | 7 | ||||||||||||||||
Fair Value Hedges | - | 1 | - | 3 | 4 | ||||||||||||||||
De-designated Risk Management Contracts (e) | - | - | - | 6 | 6 | ||||||||||||||||
Total Risk Management Assets | 22 | 565 | 142 | -272 | 457 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (f) | 8 | - | - | 11 | 19 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 609 | - | - | 609 | ||||||||||||||||
Corporate Debt | - | 37 | - | - | 37 | ||||||||||||||||
State and Local Government | - | 255 | - | - | 255 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 901 | - | - | 901 | ||||||||||||||||
Equity Securities - Domestic (b) | 1,012 | - | - | - | 1,012 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,020 | 901 | - | 11 | 1,932 | ||||||||||||||||
Total Assets | $ | 1,392 | $ | 1,475 | $ | 142 | $ | -149 | $ | 2,860 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (c) (g) | $ | 30 | $ | 475 | $ | 22 | $ | -282 | $ | 245 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (c) | - | 11 | 3 | -8 | 6 | ||||||||||||||||
Interest Rate/Foreign Currency Hedges | - | 2 | - | - | 2 | ||||||||||||||||
Fair Value Hedges | - | 11 | - | 3 | 14 | ||||||||||||||||
Total Risk Management Liabilities | $ | 30 | $ | 499 | $ | 25 | $ | -287 | $ | 267 | |||||||||||
(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 March 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. 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, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. 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 March 31, 2014 | Assets (Liabilities) | ||||||||||||||||||||
(in millions) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 117 | |||||||||||||||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) | 84 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | -10 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 9 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -100 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | -4 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | -2 | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | 11 | ||||||||||||||||||||
Balance as of March 31, 2014 | $ | 105 | |||||||||||||||||||
Net Risk Management | |||||||||||||||||||||
Three Months Ended March 31, 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) | -4 | ||||||||||||||||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) | |||||||||||||||||||||
Relating to Assets Still Held at the Reporting Date (a) | -5 | ||||||||||||||||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 1 | ||||||||||||||||||||
Purchases, Issuances and Settlements (c) | -6 | ||||||||||||||||||||
Transfers into Level 3 (d) (e) | 6 | ||||||||||||||||||||
Transfers out of Level 3 (e) (f) | - | ||||||||||||||||||||
Changes in Fair Value Allocated to Regulated Jurisdictions (g) | -2 | ||||||||||||||||||||
Balance as of March 31, 2013 | $ | 76 | |||||||||||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Fair Value | Valuation | Significant | Input/Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 116 | $ | 23 | Discounted Cash Flow | Forward Market Price (a) | $ | 1.45 | $ | 131.46 | |||||||||||
Counterparty Credit Risk (b) | 315 | ||||||||||||||||||||
FTRs | 14 | 2 | Discounted Cash Flow | Forward Market Price (a) | -5.05 | 9.17 | |||||||||||||||
Total | $ | 130 | $ | 25 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Fair Value | Valuation | Significant | Input/Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input | Low | High | ||||||||||||||||
(in millions) | |||||||||||||||||||||
Energy Contracts | $ | 132 | $ | 22 | Discounted Cash Flow | Forward Market Price (a) | $ | 11.42 | $ | 120.72 | |||||||||||
Counterparty Credit Risk (b) | 316 | ||||||||||||||||||||
FTRs | 10 | 3 | Discounted Cash Flow | Forward Market Price (a) | -5.1 | 10.44 | |||||||||||||||
Total | $ | 142 | $ | 25 | |||||||||||||||||
(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 | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 13,536 | $ | - | $ | - | $ | 36 | $ | 13,572 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | 393 | 37,854 | 10,508 | -18,979 | 29,776 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 224 | - | -15 | 209 | ||||||||||||||||
Total Risk Management Assets | 393 | 38,078 | 10,508 | -18,994 | 29,985 | ||||||||||||||||
Total Assets: | $ | 13,929 | $ | 38,078 | $ | 10,508 | $ | -18,958 | $ | 43,557 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 306 | $ | 29,386 | $ | 3,107 | $ | -20,309 | $ | 12,490 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 90 | - | -15 | 75 | ||||||||||||||||
Total Risk Management Liabilities | $ | 306 | $ | 29,476 | $ | 3,107 | $ | -20,324 | $ | 12,565 | |||||||||||
APCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 2,714 | $ | - | $ | - | $ | 36 | $ | 2,750 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | 827 | 54,448 | 12,097 | -29,616 | 37,756 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 389 | - | -26 | 363 | ||||||||||||||||
Total Risk Management Assets | 827 | 54,837 | 12,097 | -29,642 | 38,119 | ||||||||||||||||
Total Assets | $ | 3,541 | $ | 54,837 | $ | 12,097 | $ | -29,606 | $ | 40,869 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 700 | $ | 49,220 | $ | 1,535 | $ | -32,609 | $ | 18,846 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 313 | - | -26 | 287 | ||||||||||||||||
Total Risk Management Liabilities | $ | 700 | $ | 49,533 | $ | 1,535 | $ | -32,635 | $ | 19,133 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 6,454 | $ | 2,822 | Discounted Cash Flow | Forward Market Price | $ | 13.34 | $ | 59.6 | |||||||||||
FTRs | 4,054 | 285 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 10,508 | $ | 3,107 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
APCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 9,359 | $ | 960 | Discounted Cash Flow | Forward Market Price | $ | 13.04 | $ | 80.5 | |||||||||||
FTRs | 2,738 | 575 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 12,097 | $ | 1,535 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Indiana Michigan Power Co [Member] | ' | ||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
Nuclear Trust Fund Investments | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
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 | $ | 12,439 | $ | - | $ | - | $ | 18,804 | $ | - | $ | - | |||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | 606,228 | 31,666 | -3,621 | 608,875 | 26,114 | -3,824 | |||||||||||||||
Corporate Debt | 42,727 | 3,223 | -1,097 | 36,782 | 2,450 | -1,123 | |||||||||||||||
State and Local Government | 280,612 | 972 | -345 | 254,638 | 748 | -370 | |||||||||||||||
Subtotal Fixed Income Securities | 929,567 | 35,861 | -5,063 | 900,295 | 29,312 | -5,317 | |||||||||||||||
Equity Securities - Domestic | 1,020,145 | 513,803 | -79,563 | 1,012,511 | 505,538 | -81,677 | |||||||||||||||
Spent Nuclear Fuel and | |||||||||||||||||||||
Decommissioning Trusts | $ | 1,962,151 | $ | 549,664 | $ | -84,626 | $ | 1,931,610 | $ | 534,850 | $ | -86,994 | |||||||||
Securities Activity Within the Decommissioning and SNF Trusts | ' | ||||||||||||||||||||
Three Months Ended March 31, | |||||||||||||||||||||
2014 | 2013 | ||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Proceeds from Investment Sales | $ | 147,700 | $ | 167,670 | |||||||||||||||||
Purchases of Investments | 164,511 | 184,299 | |||||||||||||||||||
Gross Realized Gains on Investment Sales | 8,141 | 3,323 | |||||||||||||||||||
Gross Realized Losses on Investment Sales | 874 | 2,315 | |||||||||||||||||||
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | ' | ||||||||||||||||||||
Fair Value of | |||||||||||||||||||||
Fixed Income | |||||||||||||||||||||
Securities | |||||||||||||||||||||
(in thousands) | |||||||||||||||||||||
Within 1 year | $ | 82,190 | |||||||||||||||||||
1 year – 5 years | 386,173 | ||||||||||||||||||||
5 years – 10 years | 193,018 | ||||||||||||||||||||
After 10 years | 268,186 | ||||||||||||||||||||
Total | $ | 929,567 | |||||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 267 | $ | 28,746 | $ | 6,945 | $ | -14,037 | $ | 21,921 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 152 | - | -10 | 142 | ||||||||||||||||
Total Risk Management Assets | 267 | 28,898 | 6,945 | -14,047 | 22,063 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (d) | 3,576 | - | - | 8,863 | 12,439 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 606,228 | - | - | 606,228 | ||||||||||||||||
Corporate Debt | - | 42,727 | - | - | 42,727 | ||||||||||||||||
State and Local Government | - | 280,612 | - | - | 280,612 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 929,567 | - | - | 929,567 | ||||||||||||||||
Equity Securities - Domestic (e) | 1,020,145 | - | - | - | 1,020,145 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,023,721 | 929,567 | - | 8,863 | 1,962,151 | ||||||||||||||||
Total Assets | $ | 1,023,988 | $ | 958,465 | $ | 6,945 | $ | -5,184 | $ | 1,984,214 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 208 | $ | 22,089 | $ | 2,104 | $ | -14,940 | $ | 9,461 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 61 | - | -10 | 51 | ||||||||||||||||
Total Risk Management Liabilities | $ | 208 | $ | 22,150 | $ | 2,104 | $ | -14,950 | $ | 9,512 | |||||||||||
I&M | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 561 | $ | 38,667 | $ | 8,205 | $ | -20,766 | $ | 26,667 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 234 | - | -18 | 216 | ||||||||||||||||
Total Risk Management Assets | 561 | 38,901 | 8,205 | -20,784 | 26,883 | ||||||||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||||||||||||
Cash and Cash Equivalents (d) | 8,082 | - | - | 10,722 | 18,804 | ||||||||||||||||
Fixed Income Securities: | |||||||||||||||||||||
United States Government | - | 608,875 | - | - | 608,875 | ||||||||||||||||
Corporate Debt | - | 36,782 | - | - | 36,782 | ||||||||||||||||
State and Local Government | - | 254,638 | - | - | 254,638 | ||||||||||||||||
Subtotal Fixed Income Securities | - | 900,295 | - | - | 900,295 | ||||||||||||||||
Equity Securities - Domestic (e) | 1,012,511 | - | - | - | 1,012,511 | ||||||||||||||||
Total Spent Nuclear Fuel and Decommissioning Trusts | 1,020,593 | 900,295 | - | 10,722 | 1,931,610 | ||||||||||||||||
Total Assets | $ | 1,021,154 | $ | 939,196 | $ | 8,205 | $ | -10,062 | $ | 1,958,493 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | 475 | $ | 35,061 | $ | 1,041 | $ | -22,796 | $ | 13,781 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 212 | - | -18 | 194 | ||||||||||||||||
Total Risk Management Liabilities | $ | 475 | $ | 35,273 | $ | 1,041 | $ | -22,814 | $ | 13,975 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 4,378 | $ | 1,914 | Discounted Cash Flow | Forward Market Price | $ | 13.34 | $ | 59.6 | |||||||||||
FTRs | 2,567 | 190 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 6,945 | $ | 2,104 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
I&M | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | 6,348 | $ | 651 | Discounted Cash Flow | Forward Market Price | $ | 13.04 | $ | 80.5 | |||||||||||
FTRs | 1,857 | 390 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 8,205 | $ | 1,041 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Ohio Power Co [Member] | ' | ||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 32,054 | $ | - | $ | - | $ | 12 | $ | 32,066 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 76 | 3,990 | -86 | 3,980 | ||||||||||||||||
Total Assets | $ | 32,054 | $ | 76 | $ | 3,990 | $ | -74 | $ | 36,046 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 5 | $ | 78 | $ | -83 | $ | - | |||||||||||
OPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Restricted Cash for Securitized Funding (a) | $ | 19,387 | $ | - | $ | - | $ | 12 | $ | 19,399 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | - | 3,269 | -349 | 2,920 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 162 | - | - | 162 | ||||||||||||||||
Total Risk Management Assets | - | 162 | 3,269 | -349 | 3,082 | ||||||||||||||||
Total Assets | $ | 19,387 | $ | 162 | $ | 3,269 | $ | -337 | $ | 22,481 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | - | $ | 349 | $ | -349 | $ | - | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 3,990 | 78 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 3,990 | $ | 78 | |||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
OPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 3,269 | 349 | Discounted Cash Flow | Forward Market Price | -5.1 | 10.44 | |||||||||||||||
Total | $ | 3,269 | $ | 349 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ' | ||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 922 | $ | 481 | $ | -54 | $ | 1,349 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 4 | $ | 132 | $ | -53 | $ | 83 | |||||||||||
PSO | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 1,078 | $ | - | $ | 5 | $ | 1,083 | |||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 84 | - | - | 84 | ||||||||||||||||
Total Risk Management Assets | $ | - | $ | 1,162 | $ | - | $ | 5 | $ | 1,167 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 81 | $ | - | $ | 4 | $ | 85 | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
PSO | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 481 | 132 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 481 | $ | 132 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. | |||||||||||||||||||||
Southwestern Electric Power Co [Member] | ' | ||||||||||||||||||||
Book Values and Fair Values of Long-term Debt | ' | ||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | ||||||||||||||||||||
Company | Book Value | Fair Value | Book Value | Fair Value | |||||||||||||||||
(in thousands) | |||||||||||||||||||||
APCo | $ | 4,194,516 | $ | 4,730,819 | $ | 4,194,357 | $ | 4,587,079 | |||||||||||||
I&M | 2,012,844 | 2,203,640 | 2,039,016 | 2,174,891 | |||||||||||||||||
OPCo | 2,510,285 | 2,869,364 | 2,735,175 | 3,007,191 | |||||||||||||||||
PSO | 1,049,793 | 1,200,741 | 999,810 | 1,111,149 | |||||||||||||||||
SWEPCo | 2,041,796 | 2,277,262 | 2,043,332 | 2,214,730 | |||||||||||||||||
Fair Value, Assets and Liabilities Measured on Recurring Basis | ' | ||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 15,537 | $ | - | $ | - | $ | 2,458 | $ | 17,995 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 1,471 | 609 | -173 | 1,907 | ||||||||||||||||
Total Assets | $ | 15,537 | $ | 1,471 | $ | 609 | $ | 2,285 | $ | 19,902 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 4 | $ | 167 | $ | -171 | $ | - | |||||||||||
SWEPCo | |||||||||||||||||||||
Assets and Liabilities Measured at Fair Value on a Recurring Basis | |||||||||||||||||||||
31-Dec-13 | |||||||||||||||||||||
Level 1 | Level 2 | Level 3 | Other | Total | |||||||||||||||||
Assets: | (in thousands) | ||||||||||||||||||||
Cash and Cash Equivalents (a) | $ | 15,871 | $ | - | $ | - | $ | 1,370 | $ | 17,241 | |||||||||||
Risk Management Assets | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | - | 1,233 | - | -151 | 1,082 | ||||||||||||||||
Cash Flow Hedges: | |||||||||||||||||||||
Commodity Hedges (b) | - | 97 | - | - | 97 | ||||||||||||||||
Total Risk Management Assets | - | 1,330 | - | -151 | 1,179 | ||||||||||||||||
Total Assets | $ | 15,871 | $ | 1,330 | $ | - | $ | 1,219 | $ | 18,420 | |||||||||||
Liabilities: | |||||||||||||||||||||
Risk Management Liabilities | |||||||||||||||||||||
Risk Management Commodity Contracts (b) (c) | $ | - | $ | 154 | $ | - | $ | -154 | $ | - | |||||||||||
(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 investment in money market funds. | |||||||||||||||||||||
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”. | |||||||||||||||||||||
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo. | |||||||||||||||||||||
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||||||||||||||||||
(e) Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||||||||||||||||||
Changes in Fair Value of Net Trading Derivatives and Other Investments | ' | ||||||||||||||||||||
Three Months Ended March 31, 2014 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Balance as of December 31, 2013 | $ | 10,562 | $ | 7,164 | $ | 2,920 | $ | - | $ | - | |||||||||||
Realized Gain (Loss) Included in Net Income | |||||||||||||||||||||
(or Changes in Net Assets) (a) (b) | 29,162 | 18,219 | 30,963 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | - | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | -31,781 | -19,995 | -34,036 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | -3,825 | -2,594 | - | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -6 | -4 | - | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | 3,289 | 2,052 | 4,065 | 349 | 442 | ||||||||||||||||
Balance as of March 31, 2014 | $ | 7,401 | $ | 4,842 | $ | 3,912 | $ | 349 | $ | 442 | |||||||||||
Three Months Ended March 31, 2013 | APCo | I&M | OPCo | PSO | SWEPCo | ||||||||||||||||
(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) | -1,456 | -1,005 | -2,055 | - | - | ||||||||||||||||
Unrealized Gain (Loss) Included in Net | |||||||||||||||||||||
Income (or Changes in Net Assets) Relating | |||||||||||||||||||||
to Assets Still Held at the Reporting Date (a) | - | - | -1,988 | - | - | ||||||||||||||||
Realized and Unrealized Gains (Losses) | |||||||||||||||||||||
Included in Other Comprehensive Income | - | - | - | - | - | ||||||||||||||||
Purchases, Issuances and Settlements (c) | 257 | 179 | 366 | - | - | ||||||||||||||||
Transfers into Level 3 (d) (e) | 632 | 434 | 888 | - | - | ||||||||||||||||
Transfers out of Level 3 (e) (f) | -533 | -366 | -749 | - | - | ||||||||||||||||
Changes in Fair Value Allocated to Regulated | |||||||||||||||||||||
Jurisdictions (g) | -1,123 | -732 | 490 | - | - | ||||||||||||||||
Balance as of March 31, 2013 | $ | 8,756 | $ | 6,051 | $ | 12,381 | $ | - | $ | - | |||||||||||
(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 | ' | ||||||||||||||||||||
Significant Unobservable Inputs | |||||||||||||||||||||
31-Mar-14 | |||||||||||||||||||||
SWEPCo | |||||||||||||||||||||
Fair Value | Valuation | Significant | Forward Price Range | ||||||||||||||||||
Assets | Liabilities | Technique | Unobservable Input (a) | Low | High | ||||||||||||||||
(in thousands) | |||||||||||||||||||||
Energy Contracts | $ | - | $ | - | Discounted Cash Flow | Forward Market Price | $ | - | $ | - | |||||||||||
FTRs | 609 | 167 | Discounted Cash Flow | Forward Market Price | -5.05 | 9.17 | |||||||||||||||
Total | $ | 609 | $ | 167 | |||||||||||||||||
(a) Represents market prices in dollars per MWh. |
Financing_Activities_Tables
Financing Activities (Tables) | 3 Months Ended | |||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||
Long-term Debt | ' | |||||||||||||||||||
Type of Debt | 31-Mar-14 | 31-Dec-13 | ||||||||||||||||||
(in millions) | ||||||||||||||||||||
Senior Unsecured Notes | $ | 11,571 | $ | 11,799 | ||||||||||||||||
Pollution Control Bonds | 1,932 | 1,932 | ||||||||||||||||||
Notes Payable | 342 | 369 | ||||||||||||||||||
Securitization Bonds | 2,574 | 2,686 | ||||||||||||||||||
Spent Nuclear Fuel Obligation (a) | 265 | 265 | ||||||||||||||||||
Other Long-term Debt | 1,434 | 1,360 | ||||||||||||||||||
Fair Value of Interest Rate Hedges | -7 | -9 | ||||||||||||||||||
Unamortized Discount, Net | -24 | -25 | ||||||||||||||||||
Total Long-term Debt Outstanding | 18,087 | 18,377 | ||||||||||||||||||
Long-term Debt Due Within One Year | 1,612 | 1,549 | ||||||||||||||||||
Long-term Debt | $ | 16,475 | $ | 16,828 | ||||||||||||||||
(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 $309 million as of March 31, 2014 and December 31, 2013, 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) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50 | Variable | 2016 | |||||||||||||||
Non-Registrant: | ||||||||||||||||||||
Transource Missouri | Other Long-term Debt | 27 | Variable | 2018 | ||||||||||||||||
Total Issuances | $ | 77 | (a) | |||||||||||||||||
(a) 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: | ||||||||||||||||||||
I&M | Notes Payable | $ | 5 | Variable | 2016 | |||||||||||||||
I&M | Notes Payable | 4 | 2.12 | 2016 | ||||||||||||||||
I&M | Notes Payable | 5 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 10 | Variable | 2017 | ||||||||||||||||
I&M | Other Long-term Debt | 2 | Variable | 2015 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225 | 4.85 | 2014 | ||||||||||||||||
SWEPCo | Notes Payable | 2 | 4.58 | 2032 | ||||||||||||||||
Non-Registrant: | ||||||||||||||||||||
AEGCo | Senior Unsecured Notes | 4 | 6.33 | 2037 | ||||||||||||||||
AEP Subsidiaries | Notes Payable | 1 | Variable | 2017 | ||||||||||||||||
TCC | Securitization Bonds | 72 | 5.09 | 2015 | ||||||||||||||||
TCC | Securitization Bonds | 40 | 6.25 | 2016 | ||||||||||||||||
Total Retirements and | ||||||||||||||||||||
Principal Payments | $ | 370 | ||||||||||||||||||
Short Term Debt | ' | |||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||
Outstanding | Interest | Outstanding | Interest | |||||||||||||||||
Type of Debt | Amount | Rate (a) | Amount | Rate (a) | ||||||||||||||||
(in millions) | (in millions) | |||||||||||||||||||
Securitized Debt for Receivables (b) | $ | 700 | 0.24 | % | $ | 700 | 0.23 | % | ||||||||||||
Commercial Paper | 632 | 0.31 | % | 57 | 0.29 | % | ||||||||||||||
Total Short-term Debt | $ | 1,332 | $ | 757 | ||||||||||||||||
(a) Weighted average rate. | ||||||||||||||||||||
(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | ||||||||||||||||||||
Comparative Accounts Receivable Information | ' | |||||||||||||||||||
Three Months Ended | ||||||||||||||||||||
March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
(dollars in millions) | ||||||||||||||||||||
Effective Interest Rates on Securitization of Accounts Receivable | 0.24 | % | 0.23 | % | ||||||||||||||||
Net Uncollectible Accounts Receivable Written Off | $ | 8 | $ | 7 | ||||||||||||||||
Customer Accounts Receivable Managed Portfolio | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
(in millions) | ||||||||||||||||||||
Accounts Receivable Retained Interest and Pledged as Collateral | ||||||||||||||||||||
Less Uncollectible Accounts | $ | 997 | $ | 929 | ||||||||||||||||
Total Principal Outstanding | 700 | 700 | ||||||||||||||||||
Delinquent Securitized Accounts Receivable | 55 | 45 | ||||||||||||||||||
Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable | 17 | 16 | ||||||||||||||||||
Unbilled Receivables Related to Securitization/Sale of Accounts Receivable | 278 | 331 | ||||||||||||||||||
Appalachian Power Co [Member] | ' | |||||||||||||||||||
Long-term Debt Issuances | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
(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. | ||||||||||||||||||||
Retirements and Principal Payments | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 4.58 | 2032 | ||||||||||||||||
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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
Indiana Michigan Power Co [Member] | ' | |||||||||||||||||||
Long-term Debt Issuances | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
(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. | ||||||||||||||||||||
Retirements and Principal Payments | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 4.58 | 2032 | ||||||||||||||||
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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
Ohio Power Co [Member] | ' | |||||||||||||||||||
Long-term Debt Issuances | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
(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. | ||||||||||||||||||||
Retirements and Principal Payments | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 4.58 | 2032 | ||||||||||||||||
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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||||||||||||
Long-term Debt Issuances | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
(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. | ||||||||||||||||||||
Retirements and Principal Payments | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 4.58 | 2032 | ||||||||||||||||
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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 | ||||||||||||||||||
Southwestern Electric Power Co [Member] | ' | |||||||||||||||||||
Long-term Debt Issuances | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount (a) | Rate | Due Date | ||||||||||||||||
Issuances: | (in thousands) | (%) | ||||||||||||||||||
PSO | Other Long-term Debt | $ | 50,000 | Variable | 2016 | |||||||||||||||
(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. | ||||||||||||||||||||
Retirements and Principal Payments | ' | |||||||||||||||||||
Principal | Interest | |||||||||||||||||||
Company | Type of Debt | Amount Paid | Rate | Due Date | ||||||||||||||||
Retirements and | (in thousands) | (%) | ||||||||||||||||||
Principal Payments: | ||||||||||||||||||||
APCo | Land Note | $ | 8 | 13.718 | 2026 | |||||||||||||||
I&M | Notes Payable | 9,866 | Variable | 2017 | ||||||||||||||||
I&M | Notes Payable | 5,324 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 5,214 | Variable | 2016 | ||||||||||||||||
I&M | Notes Payable | 3,611 | 2.12 | 2016 | ||||||||||||||||
I&M | Other Long-term Debt | 2,063 | Variable | 2015 | ||||||||||||||||
I&M | Other Long-term Debt | 259 | 6 | 2025 | ||||||||||||||||
OPCo | Other Long-term Debt | 29 | 1.149 | 2028 | ||||||||||||||||
OPCo | Senior Unsecured Notes | 225,000 | 4.85 | 2014 | ||||||||||||||||
PSO | Other Long-term Debt | 102 | 3 | 2027 | ||||||||||||||||
SWEPCo | Notes Payable | 1,625 | 4.58 | 2032 | ||||||||||||||||
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 | 31-Mar-14 | Limit | ||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | - | $ | 249,630 | $ | - | $ | 164,681 | $ | 245,516 | $ | 600,000 | ||||||||
I&M | - | 158,857 | - | 92,303 | 59,162 | 500,000 | ||||||||||||||
OPCo | 55,640 | 405,350 | 25,930 | 135,747 | -27,108 | 600,000 | ||||||||||||||
PSO | 121,100 | - | 58,500 | - | -70,119 | 300,000 | ||||||||||||||
SWEPCo | 130,258 | - | 61,132 | - | -117,342 | 350,000 | ||||||||||||||
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
2014 | 2013 | |||||||||||||||||||
Maximum Interest Rate | 0.33 | % | 0.43 | % | ||||||||||||||||
Minimum Interest Rate | 0.28 | % | 0.35 | % | ||||||||||||||||
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 | |||||||||||||||||||
Three Months Ended March 31, | Three Months Ended March 31, | |||||||||||||||||||
Company | 2014 | 2013 | 2014 | 2013 | ||||||||||||||||
APCo | - | % | 0.38 | % | 0.31 | % | 0.37 | % | ||||||||||||
I&M | - | % | 0.36 | % | 0.31 | % | 0.37 | % | ||||||||||||
OPCo | 0.31 | % | 0.36 | % | 0.29 | % | 0.37 | % | ||||||||||||
PSO | 0.31 | % | 0.36 | % | - | % | 0.38 | % | ||||||||||||
SWEPCo | 0.31 | % | - | % | - | % | 0.38 | % | ||||||||||||
Accounts Receivable and Accrued Unbilled Revenues | ' | |||||||||||||||||||
March 31, | December 31, | |||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 175,738 | $ | 156,599 | ||||||||||||||||
I&M | 154,510 | 139,257 | ||||||||||||||||||
OPCo | 350,735 | 324,287 | ||||||||||||||||||
PSO | 111,522 | 115,260 | ||||||||||||||||||
SWEPCo | 145,648 | 149,337 | ||||||||||||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 2,423 | $ | 1,556 | ||||||||||||||||
I&M | 2,040 | 1,452 | ||||||||||||||||||
OPCo | 7,498 | 4,669 | ||||||||||||||||||
PSO | 1,323 | 1,414 | ||||||||||||||||||
SWEPCo | 1,566 | 1,380 | ||||||||||||||||||
Proceeds on Sale of Receivables to AEP Credit | ' | |||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||
APCo | $ | 437,196 | $ | 398,193 | ||||||||||||||||
I&M | 407,150 | 351,830 | ||||||||||||||||||
OPCo | 686,627 | 696,958 | ||||||||||||||||||
PSO | 290,217 | 240,275 | ||||||||||||||||||
SWEPCo | 390,588 | 331,936 |
Variable_Interest_Entities_Tab
Variable Interest Entities (Tables) | 3 Months Ended | |||||||||||||||||||||||||
Mar. 31, 2014 | ||||||||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | ' | |||||||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | ||||||||||||||||||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||||||||||||||||
31-Mar-14 | ||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
APCo | ||||||||||||||||||||||||||
OPCo | Appalachian | |||||||||||||||||||||||||
Ohio | Consumer | |||||||||||||||||||||||||
TCC | Phase-in- | Rate | Protected | |||||||||||||||||||||||
SWEPCo | I&M | AEP | Transition | Recovery | Relief | Cell | Transource | |||||||||||||||||||
Sabine | DCC Fuel | Credit | Funding | Funding | Funding | of EIS | Energy | |||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||
Current Assets | $ | 62 | $ | 109 | $ | 1,004 | $ | 166 | $ | 36 | $ | 16 | $ | 152 | $ | 4 | ||||||||||
Net Property, Plant and | ||||||||||||||||||||||||||
Equipment | 154 | 129 | - | - | - | - | - | 57 | ||||||||||||||||||
Other Noncurrent Assets | 50 | 45 | - | 1,861 | (a) | 242 | (b) | 374 | (c) | 3 | 5 | |||||||||||||||
Total Assets | $ | 266 | $ | 283 | $ | 1,004 | $ | 2,027 | $ | 278 | $ | 390 | $ | 155 | $ | 66 | ||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 29 | $ | 100 | $ | 894 | $ | 304 | $ | 60 | $ | 28 | $ | 48 | $ | 18 | ||||||||||
Noncurrent Liabilities | 236 | 183 | 1 | 1,705 | 217 | 360 | 67 | 28 | ||||||||||||||||||
Equity | 1 | - | 109 | 18 | 1 | 2 | 40 | 20 | ||||||||||||||||||
Total Liabilities and Equity | $ | 266 | $ | 283 | $ | 1,004 | $ | 2,027 | $ | 278 | $ | 390 | $ | 155 | $ | 66 | ||||||||||
(a) Includes an intercompany item eliminated in consolidation of $81 million. | ||||||||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $112 million. | ||||||||||||||||||||||||||
(c) Includes an intercompany item eliminated in consolidation of $4 million. | ||||||||||||||||||||||||||
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES | ||||||||||||||||||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||||||||||||||||
31-Dec-13 | ||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
APCo | ||||||||||||||||||||||||||
OPCo | Appalachian | |||||||||||||||||||||||||
Ohio | Consumer | |||||||||||||||||||||||||
TCC | Phase-in- | Rate | ||||||||||||||||||||||||
SWEPCo | I&M | AEP | Transition | Recovery | Relief | Protected Cell | ||||||||||||||||||||
Sabine | DCC Fuel | Credit | Funding | Funding | Funding | of EIS | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||||||||
Current Assets | $ | 67 | $ | 118 | $ | 935 | $ | 232 | $ | 23 | $ | 6 | $ | 143 | ||||||||||||
Net Property, Plant and Equipment | 157 | 157 | - | - | - | - | - | |||||||||||||||||||
Other Noncurrent Assets | 51 | 60 | 1 | 1,918 | (a) | 252 | (b) | 378 | (c) | 3 | ||||||||||||||||
Total Assets | $ | 275 | $ | 335 | $ | 936 | $ | 2,150 | $ | 275 | $ | 384 | $ | 146 | ||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 33 | $ | 108 | $ | 827 | $ | 312 | $ | 37 | $ | 14 | $ | 39 | ||||||||||||
Noncurrent Liabilities | 242 | 227 | 1 | 1,820 | 237 | 368 | 66 | |||||||||||||||||||
Equity | - | - | 108 | 18 | 1 | 2 | 41 | |||||||||||||||||||
Total Liabilities and Equity | $ | 275 | $ | 335 | $ | 936 | $ | 2,150 | $ | 275 | $ | 384 | $ | 146 | ||||||||||||
(a) Includes an intercompany item eliminated in consolidation of $82 million. | ||||||||||||||||||||||||||
(b) Includes an intercompany item eliminated in consolidation of $116 million. | ||||||||||||||||||||||||||
(c) Includes an intercompany item eliminated in consolidation of $4 million. | ||||||||||||||||||||||||||
Appalachian Power Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | |||||||||||||||||||||||||
Consolidated Assets and Liabilities of Variable Interest Entities | ' | |||||||||||||||||||||||||
APPALACHIAN POWER COMPANY AND SUBSIDIARIES | ||||||||||||||||||||||||||
VARIABLE INTEREST ENTITIES | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Appalachian Consumer | ||||||||||||||||||||||||||
Rate Relief Funding | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 15,981 | $ | 5,891 | ||||||||||||||||||||||
Other Noncurrent Assets (a) | 373,521 | 378,029 | ||||||||||||||||||||||||
Total Assets | $ | 389,502 | $ | 383,920 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 27,682 | $ | 14,000 | ||||||||||||||||||||||
Noncurrent Liabilities | 359,919 | 368,018 | ||||||||||||||||||||||||
Equity | 1,901 | 1,902 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 389,502 | $ | 383,920 | ||||||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively. | ||||||||||||||||||||||||||
Indiana Michigan Power Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 70,422 | $ | 58,535 | ||||||||||||||||||||||
OPCo | - | 38,711 | ||||||||||||||||||||||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | |||||||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 24,364 | $ | 24,364 | $ | 23,916 | $ | 23,916 | ||||||||||||||||||
OPCo | - | - | 12,810 | 12,810 | ||||||||||||||||||||||
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
DCC Fuel | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 109,374 | $ | 117,762 | ||||||||||||||||||||||
Net Property, Plant and Equipment | 129,013 | 156,820 | ||||||||||||||||||||||||
Other Noncurrent Assets | 44,853 | 60,450 | ||||||||||||||||||||||||
Total Assets | $ | 283,240 | $ | 335,032 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 100,141 | $ | 107,815 | ||||||||||||||||||||||
Noncurrent Liabilities | 183,099 | 227,217 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 283,240 | $ | 335,032 | ||||||||||||||||||||||
Ohio Power Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
Ohio Power Co [Member] | Billings from AEP Generating Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 70,422 | $ | 58,535 | ||||||||||||||||||||||
OPCo | - | 38,711 | ||||||||||||||||||||||||
Ohio Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on | Maximum | As Reported on | Maximum | |||||||||||||||||||||||
Company | the Balance Sheet | Exposure | the Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
I&M | $ | 24,364 | $ | 24,364 | $ | 23,916 | $ | 23,916 | ||||||||||||||||||
OPCo | - | - | 12,810 | 12,810 | ||||||||||||||||||||||
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Ohio Phase-in- | ||||||||||||||||||||||||||
Recovery Funding | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 35,958 | $ | 23,198 | ||||||||||||||||||||||
Other Noncurrent Assets (a) | 241,814 | 251,409 | ||||||||||||||||||||||||
Total Assets | $ | 277,772 | $ | 274,607 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 59,590 | $ | 36,470 | ||||||||||||||||||||||
Noncurrent Liabilities | 216,845 | 236,800 | ||||||||||||||||||||||||
Equity | 1,337 | 1,337 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 277,772 | $ | 274,607 | ||||||||||||||||||||||
(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively. | ||||||||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
Southwestern Electric Power Co [Member] | ' | |||||||||||||||||||||||||
Billings from Significant Variable Interest | ' | |||||||||||||||||||||||||
Three Months Ended March 31, | ||||||||||||||||||||||||||
Company | 2014 | 2013 | ||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 50,136 | $ | 39,040 | ||||||||||||||||||||||
I&M | 31,969 | 27,498 | ||||||||||||||||||||||||
OPCo | 39,049 | 54,069 | ||||||||||||||||||||||||
PSO | 24,439 | 18,161 | ||||||||||||||||||||||||
SWEPCo | 33,023 | 27,480 | ||||||||||||||||||||||||
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member] | ' | |||||||||||||||||||||||||
Carrying Amount and Classification of Variable Interest in Accounts Payable | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
As Reported on the | Maximum | As Reported on the | Maximum | |||||||||||||||||||||||
Company | Balance Sheet | Exposure | Balance Sheet | Exposure | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
APCo | $ | 19,304 | $ | 19,304 | $ | 20,191 | $ | 20,191 | ||||||||||||||||||
I&M | 12,040 | 12,040 | 12,864 | 12,864 | ||||||||||||||||||||||
OPCo | 14,046 | 14,046 | 31,425 | 31,425 | ||||||||||||||||||||||
PSO | 9,330 | 9,330 | 10,596 | 10,596 | ||||||||||||||||||||||
SWEPCo | 12,833 | 12,833 | 13,520 | 13,520 | ||||||||||||||||||||||
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 | ||||||||||||||||||||||||||
March 31, 2014 and December 31, 2013 | ||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||
Sabine | ||||||||||||||||||||||||||
ASSETS | 2014 | 2013 | ||||||||||||||||||||||||
Current Assets | $ | 61,675 | $ | 66,478 | ||||||||||||||||||||||
Net Property, Plant and Equipment | 153,928 | 157,274 | ||||||||||||||||||||||||
Other Noncurrent Assets | 50,140 | 51,211 | ||||||||||||||||||||||||
Total Assets | $ | 265,743 | $ | 274,963 | ||||||||||||||||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||||||||
Current Liabilities | $ | 29,257 | $ | 32,812 | ||||||||||||||||||||||
Noncurrent Liabilities | 236,142 | 241,673 | ||||||||||||||||||||||||
Equity | 344 | 478 | ||||||||||||||||||||||||
Total Liabilities and Equity | $ | 265,743 | $ | 274,963 | ||||||||||||||||||||||
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | ' | |||||||||||||||||||||||||
Companys Investment In Joint Venture | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
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 | 1,910 | 1,910 | 1,600 | 1,600 | ||||||||||||||||||||||
SWEPCo's Guarantee of Debt | - | 85,190 | - | 61,348 | ||||||||||||||||||||||
Total Investment in DHLC | $ | 9,553 | $ | 94,743 | $ | 9,243 | $ | 70,591 | ||||||||||||||||||
PATH West Virginia Transmission Co, LLC [Member] | ' | |||||||||||||||||||||||||
Companys Investment In Joint Venture | ' | |||||||||||||||||||||||||
31-Mar-14 | 31-Dec-13 | |||||||||||||||||||||||||
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 | 6 | 6 | 6 | 6 | ||||||||||||||||||||||
Total Investment in PATH-WV | $ | 25 | $ | 25 | $ | 25 | $ | 25 |
Significant_Accounting_Matters3
Significant Accounting Matters (Details) (USD $) | 3 Months Ended | |
In Thousands, except Share data, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Basic and Diluted EPS Calculations | ' | ' |
Earnings Attributable to AEP Common Shareholders | $560,000 | $363,000 |
Weighted Average Number of Basic AEP Common Shares Outstanding | 487,867,089 | 485,823,668 |
Total Basic Earnings Per Share Attributable to AEP Common Shareholders | $1.15 | $0.75 |
Weighted Average Dilutive Effect of: | ' | ' |
Weighted Average Number of Diluted AEP Common Shares Outstanding | 488,271,167 | 486,344,036 |
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders | $1.15 | $0.75 |
Amounts Attributable to AEP Common Shareholders | ' | ' |
Net Income | 560,000 | 363,000 |
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract] | ' | ' |
Antidilutive Shares Outstanding | 0 | 0 |
Southwestern Electric Power Co [Member] | ' | ' |
Basic and Diluted EPS Calculations | ' | ' |
Earnings Attributable to AEP Common Shareholders | 21,860 | 10,458 |
Amounts Attributable to AEP Common Shareholders | ' | ' |
Net Income | $21,860 | $10,458 |
Employee Stock Option [Member] | ' | ' |
Weighted Average Dilutive Effect of: | ' | ' |
Weighted Average Dilutive Effect of Shares | 0 | 0 |
Dilutive Securities, Effect on Basic Earnings Per Share | $0 | $0 |
Restricted Stock Units [Member] | ' | ' |
Weighted Average Dilutive Effect of: | ' | ' |
Weighted Average Dilutive Effect of Shares | 400,000 | 500,000 |
Dilutive Securities, Effect on Basic Earnings Per Share | $0 | $0 |
Comprehensive_Income_Details
Comprehensive Income (Details) (USD $) | 3 Months Ended | |||
Mar. 31, 2014 | Mar. 31, 2013 | |||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | ($115,000,000) | ($337,000,000) | ||
Change in Fair Value Recognized in AOCI | -14,000,000 | 22,000,000 | ||
Amounts Reclassified from AOCI | 20,000,000 | 9,000,000 | ||
Net Current Period Other Comprehensive Income | 6,000,000 | 31,000,000 | ||
Ending Balance in AOCI | -109,000,000 | -306,000,000 | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 2,549,000,000 | 2,356,000,000 | ||
Generation & Marketing Revenues | 117,000,000 | 122,000,000 | ||
Purchased Electricity for Resale | 638,000,000 | 371,000,000 | ||
Other Operation Expense | 780,000,000 | 738,000,000 | ||
Maintenance Expense | 292,000,000 | 293,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 491,000,000 | 420,000,000 | ||
Interest Expense | 220,000,000 | 232,000,000 | ||
Income Tax (Expense) Credit | -307,000,000 | -195,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest and Investment Income | 1,000,000 | 3,000,000 | ||
Interest Expense | 220,000,000 | 232,000,000 | ||
Income Tax (Expense) Credit | -307,000,000 | -195,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -307,000,000 | -195,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Securities Available for Sale [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 7,000,000 | 4,000,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 1,000,000 | ||
Amounts Reclassified from AOCI | 0 | 0 | ||
Net Current Period Other Comprehensive Income | 0 | 1,000,000 | ||
Ending Balance in AOCI | 7,000,000 | 5,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -99,000,000 | -303,000,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | 1,000,000 | 6,000,000 | ||
Net Current Period Other Comprehensive Income | 1,000,000 | 6,000,000 | ||
Ending Balance in AOCI | -98,000,000 | -297,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 0 | -8,000,000 | ||
Change in Fair Value Recognized in AOCI | -14,000,000 | 18,000,000 | ||
Amounts Reclassified from AOCI | 18,000,000 | 2,000,000 | ||
Net Current Period Other Comprehensive Income | 4,000,000 | 20,000,000 | ||
Ending Balance in AOCI | 4,000,000 | 12,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 18,000,000 | 2,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 18,000,000 | 2,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 18,000,000 | 2,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 18,000,000 | 2,000,000 | ||
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -23,000,000 | -30,000,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 3,000,000 | ||
Amounts Reclassified from AOCI | 1,000,000 | 1,000,000 | ||
Net Current Period Other Comprehensive Income | 1,000,000 | 4,000,000 | ||
Ending Balance in AOCI | -22,000,000 | -26,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 1,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 1,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 1,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 1,000,000 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 20,000,000 | 9,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 20,000,000 | 9,000,000 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 19,000,000 | 3,000,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 30,000,000 | 5,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 30,000,000 | 5,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 30,000,000 | 5,000,000 | ||
Income Tax (Expense) Credit | 11,000,000 | 2,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19,000,000 | 3,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 30,000,000 | 5,000,000 | ||
Income Tax (Expense) Credit | 11,000,000 | 2,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19,000,000 | 3,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 30,000,000 | 5,000,000 | ||
Income Tax (Expense) Credit | 11,000,000 | 2,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19,000,000 | 3,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 19,000,000 | 3,000,000 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 0 | 0 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 0 | 0 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | 0 | 0 | ||
Subtotal - Interest Rate and Foreign Currency | 0 | 0 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | ||
Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest and Investment Income | 0 | 0 | ||
Interest Expense | 0 | 0 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | ||
Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | ||
Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 1,000,000 | 6,000,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 2,000,000 | 9,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 2,000,000 | 9,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 9,000,000 | ||
Income Tax (Expense) Credit | 1,000,000 | 3,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 9,000,000 | ||
Income Tax (Expense) Credit | 1,000,000 | 3,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Pension and OPEB | ' | ' | ||
Amortization of Prior Service Cost (Credit) | -5,000,000 | -5,000,000 | ||
Amortization of Actuarial (Gains)/Losses | 7,000,000 | 14,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 9,000,000 | ||
Income Tax (Expense) Credit | 1,000,000 | 3,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 1,000,000 | 6,000,000 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 0 | 0 | ||
Generation & Marketing Revenues | 0 | -3,000,000 | ||
Purchased Electricity for Resale | 31,000,000 | 6,000,000 | ||
Property, Plant and Equipment | 0 | 0 | ||
Regulatory Assets/(Liabilities), Net | -3,000,000 | [1] | 0 | [1] |
Subtotal - Commodity | 28,000,000 | 3,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 28,000,000 | 3,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 28,000,000 | 3,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 28,000,000 | 3,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 28,000,000 | 3,000,000 | ||
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 2,000,000 | 2,000,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | 2,000,000 | 2,000,000 | ||
Subtotal - Interest Rate and Foreign Currency | 2,000,000 | 2,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 2,000,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 2,000,000 | 2,000,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 2,000,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 2,000,000 | 2,000,000 | ||
Appalachian Power Co [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 2,951,000 | -29,898,000 | ||
Change in Fair Value Recognized in AOCI | 1,583,000 | 793,000 | ||
Amounts Reclassified from AOCI | -1,670,000 | 823,000 | ||
Net Current Period Other Comprehensive Income | -87,000 | 1,616,000 | ||
Ending Balance in AOCI | 2,864,000 | -28,282,000 | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 866,457,000 | 872,732,000 | ||
Generation & Marketing Revenues | 2,020,000 | 1,902,000 | ||
Purchased Electricity for Resale | 168,991,000 | 65,456,000 | ||
Other Operation Expense | 93,538,000 | 78,908,000 | ||
Maintenance Expense | 60,090,000 | 99,386,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 104,586,000 | 87,903,000 | ||
Interest Expense | 51,672,000 | 48,204,000 | ||
Income Tax (Expense) Credit | -66,248,000 | -47,012,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 51,672,000 | 48,204,000 | ||
Income Tax (Expense) Credit | -66,248,000 | -47,012,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -66,248,000 | -47,012,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Appalachian Power Co [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -233,000 | -31,331,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | -333,000 | 358,000 | ||
Net Current Period Other Comprehensive Income | -333,000 | 358,000 | ||
Ending Balance in AOCI | -566,000 | -30,973,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 94,000 | -644,000 | ||
Change in Fair Value Recognized in AOCI | 1,583,000 | 794,000 | ||
Amounts Reclassified from AOCI | -1,590,000 | 211,000 | ||
Net Current Period Other Comprehensive Income | -7,000 | 1,005,000 | ||
Ending Balance in AOCI | 87,000 | 361,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,590,000 | 211,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,590,000 | 211,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,590,000 | 211,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,590,000 | 211,000 | ||
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 3,090,000 | 2,077,000 | ||
Change in Fair Value Recognized in AOCI | 0 | -1,000 | ||
Amounts Reclassified from AOCI | 253,000 | 254,000 | ||
Net Current Period Other Comprehensive Income | 253,000 | 253,000 | ||
Ending Balance in AOCI | 3,343,000 | 2,330,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 253,000 | 254,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 253,000 | 254,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 253,000 | 254,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 253,000 | 254,000 | ||
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -1,670,000 | 823,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,670,000 | 823,000 | ||
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -1,337,000 | 465,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -2,056,000 | 715,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -2,056,000 | 715,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,056,000 | 715,000 | ||
Income Tax (Expense) Credit | -719,000 | 250,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337,000 | 465,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,056,000 | 715,000 | ||
Income Tax (Expense) Credit | -719,000 | 250,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337,000 | 465,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,056,000 | 715,000 | ||
Income Tax (Expense) Credit | -719,000 | 250,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337,000 | 465,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,337,000 | 465,000 | ||
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -333,000 | 358,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -512,000 | 551,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -512,000 | 551,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -512,000 | 551,000 | ||
Income Tax (Expense) Credit | -179,000 | 193,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -512,000 | 551,000 | ||
Income Tax (Expense) Credit | -179,000 | 193,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Pension and OPEB | ' | ' | ||
Amortization of Prior Service Cost (Credit) | -1,282,000 | -1,282,000 | ||
Amortization of Actuarial (Gains)/Losses | 770,000 | 1,833,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -512,000 | 551,000 | ||
Income Tax (Expense) Credit | -179,000 | 193,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -333,000 | 358,000 | ||
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 0 | 20,000 | ||
Purchased Electricity for Resale | -462,000 | 57,000 | ||
Other Operation Expense | -10,000 | -11,000 | ||
Maintenance Expense | -20,000 | -16,000 | ||
Property, Plant and Equipment | -17,000 | -14,000 | ||
Regulatory Assets/(Liabilities), Net | -1,937,000 | [1] | 289,000 | [1] |
Subtotal - Commodity | -2,446,000 | 325,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -2,446,000 | 325,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,446,000 | 325,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,446,000 | 325,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -2,446,000 | 325,000 | ||
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 390,000 | 390,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | 390,000 | 390,000 | ||
Subtotal - Interest Rate and Foreign Currency | 390,000 | 390,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 390,000 | 390,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 390,000 | 390,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 390,000 | 390,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 390,000 | 390,000 | ||
Indiana Michigan Power Co [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -15,509,000 | -28,883,000 | ||
Change in Fair Value Recognized in AOCI | 1,062,000 | 2,781,000 | ||
Amounts Reclassified from AOCI | -594,000 | 518,000 | ||
Net Current Period Other Comprehensive Income | 468,000 | 3,299,000 | ||
Ending Balance in AOCI | -15,041,000 | -25,584,000 | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 614,843,000 | 490,603,000 | ||
Generation & Marketing Revenues | 0 | 1,988,000 | ||
Purchased Electricity for Resale | 5,362,000 | 41,812,000 | ||
Other Operation Expense | 141,350,000 | 145,238,000 | ||
Maintenance Expense | 48,565,000 | 45,514,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 50,031,000 | 40,902,000 | ||
Interest Expense | 25,633,000 | 24,211,000 | ||
Income Tax (Expense) Credit | -38,315,000 | -21,263,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 25,633,000 | 24,211,000 | ||
Income Tax (Expense) Credit | -38,315,000 | -21,263,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -38,315,000 | -21,263,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 421,000 | -8,790,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | 43,000 | 176,000 | ||
Net Current Period Other Comprehensive Income | 43,000 | 176,000 | ||
Ending Balance in AOCI | 464,000 | -8,614,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Indiana Michigan Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 46,000 | -446,000 | ||
Change in Fair Value Recognized in AOCI | 1,062,000 | 532,000 | ||
Amounts Reclassified from AOCI | -1,047,000 | 150,000 | ||
Net Current Period Other Comprehensive Income | 15,000 | 682,000 | ||
Ending Balance in AOCI | 61,000 | 236,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,047,000 | 150,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,047,000 | 150,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,047,000 | 150,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -1,047,000 | 150,000 | ||
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -15,976,000 | -19,647,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 2,249,000 | ||
Amounts Reclassified from AOCI | 410,000 | 192,000 | ||
Net Current Period Other Comprehensive Income | 410,000 | 2,441,000 | ||
Ending Balance in AOCI | -15,566,000 | -17,206,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 410,000 | 192,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 410,000 | 192,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 410,000 | 192,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 410,000 | 192,000 | ||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -594,000 | 518,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -594,000 | 518,000 | ||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -637,000 | 342,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -980,000 | 526,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -980,000 | 526,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -980,000 | 526,000 | ||
Income Tax (Expense) Credit | -343,000 | 184,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637,000 | 342,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -980,000 | 526,000 | ||
Income Tax (Expense) Credit | -343,000 | 184,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637,000 | 342,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -980,000 | 526,000 | ||
Income Tax (Expense) Credit | -343,000 | 184,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637,000 | 342,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -637,000 | 342,000 | ||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 43,000 | 176,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 66,000 | 270,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 66,000 | 270,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 66,000 | 270,000 | ||
Income Tax (Expense) Credit | 23,000 | 94,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 66,000 | 270,000 | ||
Income Tax (Expense) Credit | 23,000 | 94,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Pension and OPEB | ' | ' | ||
Amortization of Prior Service Cost (Credit) | -199,000 | -199,000 | ||
Amortization of Actuarial (Gains)/Losses | 265,000 | 469,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 66,000 | 270,000 | ||
Income Tax (Expense) Credit | 23,000 | 94,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 43,000 | 176,000 | ||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 0 | 52,000 | ||
Purchased Electricity for Resale | -717,000 | 149,000 | ||
Other Operation Expense | -7,000 | -7,000 | ||
Maintenance Expense | -7,000 | -7,000 | ||
Property, Plant and Equipment | -10,000 | -7,000 | ||
Regulatory Assets/(Liabilities), Net | -870,000 | [1] | 50,000 | [1] |
Subtotal - Commodity | -1,611,000 | 230,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -1,611,000 | 230,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -1,611,000 | 230,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -1,611,000 | 230,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -1,611,000 | 230,000 | ||
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 631,000 | 296,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | 631,000 | 296,000 | ||
Subtotal - Interest Rate and Foreign Currency | 631,000 | 296,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 631,000 | 296,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 631,000 | 296,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 631,000 | 296,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 631,000 | 296,000 | ||
Ohio Power Co [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 7,079,000 | -165,725,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 1,102,000 | ||
Amounts Reclassified from AOCI | -448,000 | 3,233,000 | ||
Net Current Period Other Comprehensive Income | -448,000 | 4,335,000 | ||
Ending Balance in AOCI | 6,631,000 | -161,390,000 | ||
Commodity | ' | ' | ||
Generation & Marketing Revenues | 1,308,000 | 6,627,000 | ||
Purchased Electricity for Resale | 79,130,000 | 43,185,000 | ||
Other Operation Expense | 151,426,000 | 184,187,000 | ||
Maintenance Expense | 34,651,000 | 74,295,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 58,699,000 | 92,324,000 | ||
Interest Expense | 33,007,000 | 50,173,000 | ||
Income Tax (Expense) Credit | -34,052,000 | -69,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 33,007,000 | 50,173,000 | ||
Income Tax (Expense) Credit | -34,052,000 | -69,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -34,052,000 | -69,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Ohio Power Co [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 0 | -172,908,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | 0 | 3,269,000 | ||
Net Current Period Other Comprehensive Income | 0 | 3,269,000 | ||
Ending Balance in AOCI | 0 | -169,639,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Ohio Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 105,000 | -912,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 1,102,000 | ||
Amounts Reclassified from AOCI | -105,000 | 304,000 | ||
Net Current Period Other Comprehensive Income | -105,000 | 1,406,000 | ||
Ending Balance in AOCI | 0 | 494,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -105,000 | 304,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -105,000 | 304,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -105,000 | 304,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -105,000 | 304,000 | ||
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 6,974,000 | 8,095,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | -343,000 | -340,000 | ||
Net Current Period Other Comprehensive Income | -343,000 | -340,000 | ||
Ending Balance in AOCI | 6,631,000 | 7,755,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -343,000 | -340,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -343,000 | -340,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -343,000 | -340,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -343,000 | -340,000 | ||
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -448,000 | 3,233,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | 3,233,000 | ||
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -448,000 | -36,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -689,000 | -55,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -689,000 | -55,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -689,000 | -55,000 | ||
Income Tax (Expense) Credit | -241,000 | -19,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | -36,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -689,000 | -55,000 | ||
Income Tax (Expense) Credit | -241,000 | -19,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | -36,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -689,000 | -55,000 | ||
Income Tax (Expense) Credit | -241,000 | -19,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | -36,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -448,000 | -36,000 | ||
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 0 | 3,269,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 0 | 5,029,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 0 | 5,029,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 5,029,000 | ||
Income Tax (Expense) Credit | 0 | 1,760,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 5,029,000 | ||
Income Tax (Expense) Credit | 0 | 1,760,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Pension and OPEB | ' | ' | ||
Amortization of Prior Service Cost (Credit) | 0 | -1,468,000 | ||
Amortization of Actuarial (Gains)/Losses | 0 | 6,497,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 5,029,000 | ||
Income Tax (Expense) Credit | 0 | 1,760,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 3,269,000 | ||
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 0 | 134,000 | ||
Purchased Electricity for Resale | 0 | 382,000 | ||
Other Operation Expense | -11,000 | -18,000 | ||
Maintenance Expense | -11,000 | -12,000 | ||
Property, Plant and Equipment | -18,000 | -19,000 | ||
Regulatory Assets/(Liabilities), Net | -122,000 | [1] | 0 | [1] |
Subtotal - Commodity | -162,000 | 467,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -162,000 | 467,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -162,000 | 467,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -162,000 | 467,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -162,000 | 467,000 | ||
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -527,000 | -522,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | -3,000 | 2,000 | ||
Interest Expense | -524,000 | -524,000 | ||
Subtotal - Interest Rate and Foreign Currency | -527,000 | -522,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -527,000 | -522,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | -524,000 | -524,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -527,000 | -522,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -527,000 | -522,000 | ||
Public Service Co Of Oklahoma [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 5,758,000 | 6,481,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 36,000 | ||
Amounts Reclassified from AOCI | -246,000 | -203,000 | ||
Net Current Period Other Comprehensive Income | -246,000 | -167,000 | ||
Ending Balance in AOCI | 5,512,000 | 6,314,000 | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 296,710,000 | 259,903,000 | ||
Generation & Marketing Revenues | 78,000 | 552,000 | ||
Purchased Electricity for Resale | 79,691,000 | 64,655,000 | ||
Other Operation Expense | 58,711,000 | 47,807,000 | ||
Maintenance Expense | 24,745,000 | 28,572,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 23,982,000 | 24,180,000 | ||
Interest Expense | 13,317,000 | 13,340,000 | ||
Income Tax (Expense) Credit | -4,989,000 | -8,634,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 13,317,000 | 13,340,000 | ||
Income Tax (Expense) Credit | -4,989,000 | -8,634,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -4,989,000 | -8,634,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Public Service Co Of Oklahoma [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 57,000 | 21,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 36,000 | ||
Amounts Reclassified from AOCI | -57,000 | -13,000 | ||
Net Current Period Other Comprehensive Income | -57,000 | 23,000 | ||
Ending Balance in AOCI | 0 | 44,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -57,000 | -13,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -57,000 | -13,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -57,000 | -13,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -57,000 | -13,000 | ||
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 5,701,000 | 6,460,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | -189,000 | -190,000 | ||
Net Current Period Other Comprehensive Income | -189,000 | -190,000 | ||
Ending Balance in AOCI | 5,512,000 | 6,270,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -189,000 | -190,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -189,000 | -190,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -189,000 | -190,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -189,000 | -190,000 | ||
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -246,000 | -203,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -246,000 | -203,000 | ||
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -380,000 | -312,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -380,000 | -312,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -380,000 | -312,000 | ||
Income Tax (Expense) Credit | -134,000 | -109,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -380,000 | -312,000 | ||
Income Tax (Expense) Credit | -134,000 | -109,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -380,000 | -312,000 | ||
Income Tax (Expense) Credit | -134,000 | -109,000 | ||
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Other Operation Expense | -8,000 | -9,000 | ||
Maintenance Expense | -9,000 | -4,000 | ||
Property, Plant and Equipment | -13,000 | -7,000 | ||
Regulatory Assets/(Liabilities), Net | -58,000 | [1] | 0 | [1] |
Subtotal - Commodity | -88,000 | -20,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -88,000 | -20,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -88,000 | -20,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -88,000 | -20,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -88,000 | -20,000 | ||
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -292,000 | -292,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | -292,000 | -292,000 | ||
Subtotal - Interest Rate and Foreign Currency | -292,000 | -292,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -292,000 | -292,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | -292,000 | -292,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -292,000 | -292,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -292,000 | -292,000 | ||
Southwestern Electric Power Co [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -8,444,000 | -17,860,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 44,000 | ||
Amounts Reclassified from AOCI | 268,000 | 489,000 | ||
Net Current Period Other Comprehensive Income | 268,000 | 533,000 | ||
Ending Balance in AOCI | -8,176,000 | -17,327,000 | ||
Commodity | ' | ' | ||
Vertically Integrated Utilities Revenues | 426,627,000 | 381,277,000 | ||
Generation & Marketing Revenues | 365,000 | 331,000 | ||
Purchased Electricity for Resale | 61,165,000 | 39,760,000 | ||
Other Operation Expense | 68,537,000 | 59,448,000 | ||
Maintenance Expense | 30,411,000 | 27,791,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Depreciation and Amortization Expense | 45,661,000 | 44,882,000 | ||
Interest Expense | 31,876,000 | 33,990,000 | ||
Income Tax (Expense) Credit | -12,165,000 | -6,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 31,876,000 | 33,990,000 | ||
Income Tax (Expense) Credit | -12,165,000 | -6,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Pension and OPEB | ' | ' | ||
Income Tax (Expense) Credit | -12,165,000 | -6,796,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 4,794,000 | -2,311,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | -234,000 | -63,000 | ||
Net Current Period Other Comprehensive Income | -234,000 | -63,000 | ||
Ending Balance in AOCI | 4,560,000 | -2,374,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Southwestern Electric Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | 66,000 | 22,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 44,000 | ||
Amounts Reclassified from AOCI | -66,000 | -15,000 | ||
Net Current Period Other Comprehensive Income | -66,000 | 29,000 | ||
Ending Balance in AOCI | 0 | 51,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -66,000 | -15,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -66,000 | -15,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -66,000 | -15,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -66,000 | -15,000 | ||
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Beginning Balance in AOCI | -13,304,000 | -15,571,000 | ||
Change in Fair Value Recognized in AOCI | 0 | 0 | ||
Amounts Reclassified from AOCI | 568,000 | 567,000 | ||
Net Current Period Other Comprehensive Income | 568,000 | 567,000 | ||
Ending Balance in AOCI | -12,736,000 | -15,004,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 568,000 | 567,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 568,000 | 567,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 568,000 | 567,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 568,000 | 567,000 | ||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 268,000 | 489,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 268,000 | 489,000 | ||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | 502,000 | 552,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 771,000 | 849,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | 771,000 | 849,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 771,000 | 849,000 | ||
Income Tax (Expense) Credit | 269,000 | 297,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502,000 | 552,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 771,000 | 849,000 | ||
Income Tax (Expense) Credit | 269,000 | 297,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502,000 | 552,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 771,000 | 849,000 | ||
Income Tax (Expense) Credit | 269,000 | 297,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502,000 | 552,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 502,000 | 552,000 | ||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ' | ' | ||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ' | ' | ||
Amounts Reclassified from AOCI | -234,000 | -63,000 | ||
Commodity | ' | ' | ||
Subtotal - Commodity | -360,000 | -97,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -360,000 | -97,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -360,000 | -97,000 | ||
Income Tax (Expense) Credit | -126,000 | -34,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -360,000 | -97,000 | ||
Income Tax (Expense) Credit | -126,000 | -34,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Pension and OPEB | ' | ' | ||
Amortization of Prior Service Cost (Credit) | -478,000 | -445,000 | ||
Amortization of Actuarial (Gains)/Losses | 118,000 | 348,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -360,000 | -97,000 | ||
Income Tax (Expense) Credit | -126,000 | -34,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | -234,000 | -63,000 | ||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Other Operation Expense | -13,000 | -10,000 | ||
Maintenance Expense | -10,000 | -6,000 | ||
Property, Plant and Equipment | -11,000 | -7,000 | ||
Regulatory Assets/(Liabilities), Net | -67,000 | [1] | 0 | [1] |
Subtotal - Commodity | -101,000 | -23,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Subtotal - Interest Rate and Foreign Currency | -101,000 | -23,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -101,000 | -23,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -101,000 | -23,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | -101,000 | -23,000 | ||
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member] | ' | ' | ||
Commodity | ' | ' | ||
Subtotal - Commodity | 872,000 | 872,000 | ||
Interest Rate and Foreign Currency | ' | ' | ||
Interest Expense | 872,000 | 872,000 | ||
Subtotal - Interest Rate and Foreign Currency | 872,000 | 872,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 872,000 | 872,000 | ||
Gains and Losses on Securities Available for Sale | ' | ' | ||
Interest Expense | 872,000 | 872,000 | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 872,000 | 872,000 | ||
Pension and OPEB | ' | ' | ||
Reclassifications from AOCI, before Income Tax (Expense) Credit | $872,000 | $872,000 | ||
[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 $) | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 |
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] | Ohio Economic Development Rider [Member] | Ohio Economic Development Rider [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | IGCC Pre-Construction Costs [Member] | IGCC Pre-Construction Costs [Member] | Indiana Under-Recovered Capacity Costs | Indiana Under-Recovered Capacity Costs | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [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] | Ormet Special Rate Recovery Mechanism [Member] | Ormet Special Rate Recovery Mechanism [Member] | Storm Costs [Member] | Storm Costs [Member] | Storm Costs [Member] | Storm Costs [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] | 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] | Indiana Michigan Power Co [Member] | Indiana Michigan Power Co [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] | 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] | Indiana 2011 Base Rate Case [Member] | Indiana 2011 Base Rate Case [Member] | Louisiana 2012 Formula Rate Filing [Member] | Louisiana 2012 Formula Rate Filing [Member] | Louisiana 2014 Formula Rate Filing [Member] | Louisiana 2014 Formula Rate 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 Fuel Adjustment Clause Audit - 2009 [Member] | Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ohio IGCC Plant [Member] | Ohio IGCC Plant [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Plant Transfer [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Oklahoma 2014 Base Rate Case [Member] | Ormet | Ormet | Ormet | Ormet | Storm Damage Recovery Rider [Member] | Storm Damage Recovery Rider [Member] | Texas 2012 Base Rate Case [Member] | Texas 2012 Base Rate Case [Member] | Texas 2012 Base Rate Case [Member] | Texas 2012 Base Rate Case [Member] | Texas Transmission Cost Recovery Factor Filing - 2013 [Member] | Texas Transmission Cost Recovery Factor Filing - 2013 [Member] | Virginia 2014 Biennial Base Rate Case [Member] | Virginia 2014 Biennial Base Rate Case [Member] | Virginia Transmission Rate Adjustment Clause - 2013 [Member] | Virginia Transmission Rate Adjustment Clause - 2013 [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] | Expanded Net Energy Charge - Coal Inventory [Member] | Expanded Net Energy Charge - Coal Inventory [Member] | IGCC Pre-Construction Costs [Member] | IGCC Pre-Construction Costs [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Mountaineer Carbon Capture and Storage Product Validation Facility [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Transmission Agreement Phase-In [Member] | Transmission Agreement Phase-In [Member] | Virginia Demand Response Program Costs [Member] | Virginia Demand Response Program Costs [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Virginia Environmental Rate Adjustment Clause [Member] | Regulatory Assets Not Yet Being Recovered [Member] | 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] | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Rate Case Expenses [Member] | Rate Case Expenses [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Ohio Economic Development Rider [Member] | Ohio Economic Development Rider [Member] | Ormet Special Rate Recovery Mechanism [Member] | Ormet Special Rate Recovery Mechanism [Member] | Storm Costs [Member] | Storm Costs [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] | Storm Costs [Member] | Storm Costs [Member] | Tanners Creek Plant, Units 1-4 [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Regulatory Assets Not Yet Being Recovered [Member] | Cook Plant Turbine [Member] | Cook Plant Turbine [Member] | Indiana Deferred Cook Plant Life Cycle Management Project Costs [Member] | Indiana Deferred Cook Plant Life Cycle Management Project Costs [Member] | Indiana Under-Recovered Capacity Costs | Indiana Under-Recovered Capacity Costs | Other Regulatory Assets Not Yet Being Recovered [Member] | Other Regulatory Assets Not Yet Being Recovered [Member] | Storm Costs [Member] | Storm Costs [Member] | Stranded Costs on Abandoned Plants [Member] | Stranded Costs on Abandoned Plants [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] | Indiana Michigan Power Co [Member] | Indiana Filing [Member] | Indiana Filing [Member] | Indiana Michigan Power Co [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member] | Southwestern Electric Power Co [Member] | Deferred Capacity Costs [Member] | Deferred Fuel Costs [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Subsequent Event [Member] | Appalachian Power Co [Member] | Terms Of Kentucky Power Co Settlement Agreement [Member] | Terms Of Kentucky Power Co Settlement Agreement [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [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] | Subsequent Event [Member] | Ohio Power Co [Member] | Ohio Power Co [Member] | Subsequent Event [Member] | Ohio Power Co [Member] | Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Appalachian 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 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 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] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Appalachian Power Co [Member] | Indiana Michigan Power Co [Member] | Subsequent Event [Member] | Deferred Capacity Costs [Member] | Deferred Fuel Costs [Member] | Subsequent Event [Member] | Big Sandy Plant, Unit 1 Natural Gas Conversion [Member] | Minimum [Member] | Maximum [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Subsequent Event [Member] | Welsh Plant, Unit 2 [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] | 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] | Minimum [Member] | Maximum [Member] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets Not Being Recovered [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | $4,384,000,000 | $4,376,000,000 | ' | ' | $250,000,000 | $330,000,000 | $0 | $14,000,000 | $19,000,000 | $21,000,000 | $21,000,000 | $0 | $28,000,000 | $22,000,000 | $13,000,000 | $13,000,000 | $0 | $4,000,000 | $34,000,000 | $37,000,000 | $10,000,000 | $36,000,000 | $21,000,000 | $22,000,000 | $104,000,000 | $161,000,000 | $1,006,426,000 | $1,003,890,000 | $130,904,000 | $111,218,000 | $18,818,000 | $20,528,000 | $20,528,000 | $0 | $1,287,000 | $1,287,000 | $13,264,000 | $13,264,000 | $513,000 | $168,000 | $65,206,000 | $65,206,000 | $3,450,000 | $3,313,000 | $5,897,000 | $5,012,000 | $1,941,000 | $2,440,000 | $367,406,000 | $369,905,000 | $11,098,000 | $11,028,000 | $1,143,000 | $1,143,000 | $2,025,000 | $1,951,000 | $7,930,000 | $7,934,000 | $1,398,055,000 | $1,378,697,000 | $12,118,000 | $107,074,000 | $0 | $13,854,000 | $10,483,000 | $35,631,000 | $1,635,000 | $57,589,000 | $164,929,000 | $156,690,000 | $20,172,000 | $19,588,000 | $1,079,000 | $845,000 | $19,093,000 | $18,743,000 | $505,750,000 | $524,114,000 | ' | $37,729,000 | $35,386,000 | $4,238,000 | $3,452,000 | $0 | $4,093,000 | $28,149,000 | $21,945,000 | $694,000 | $164,000 | $751,000 | $1,836,000 | $3,897,000 | $3,896,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $348,000,000 | $426,000,000 | ' | $348,000,000 | $426,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Rate Matters (Textuals) [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Regulatory Assets, Noncurrent | 4,384,000,000 | 4,376,000,000 | ' | ' | 250,000,000 | 330,000,000 | 0 | 14,000,000 | 19,000,000 | 21,000,000 | 21,000,000 | 0 | 28,000,000 | 22,000,000 | 13,000,000 | 13,000,000 | 0 | 4,000,000 | 34,000,000 | 37,000,000 | 10,000,000 | 36,000,000 | 21,000,000 | 22,000,000 | 104,000,000 | 161,000,000 | 1,006,426,000 | 1,003,890,000 | 130,904,000 | 111,218,000 | 18,818,000 | 20,528,000 | 20,528,000 | 0 | 1,287,000 | 1,287,000 | 13,264,000 | 13,264,000 | 513,000 | 168,000 | 65,206,000 | 65,206,000 | 3,450,000 | 3,313,000 | 5,897,000 | 5,012,000 | 1,941,000 | 2,440,000 | 367,406,000 | 369,905,000 | 11,098,000 | 11,028,000 | 1,143,000 | 1,143,000 | 2,025,000 | 1,951,000 | 7,930,000 | 7,934,000 | 1,398,055,000 | 1,378,697,000 | 12,118,000 | 107,074,000 | 0 | 13,854,000 | 10,483,000 | 35,631,000 | 1,635,000 | 57,589,000 | 164,929,000 | 156,690,000 | 20,172,000 | 19,588,000 | 1,079,000 | 845,000 | 19,093,000 | 18,743,000 | 505,750,000 | 524,114,000 | ' | 37,729,000 | 35,386,000 | 4,238,000 | 3,452,000 | 0 | 4,093,000 | 28,149,000 | 21,945,000 | 694,000 | 164,000 | 751,000 | 1,836,000 | 3,897,000 | 3,896,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 348,000,000 | 426,000,000 | ' | 348,000,000 | 426,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential Refund of Carrying Costs Due to an Accumulated Deferred Income Tax Credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 30,000,000 | ' | ' | 30,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Potential Refund of Unrecognized Equity Carrying Costs Due to an Accumulated Deferred Income Tax Credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Future Commitment to Support the Development of a Large Solar Farm | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | ' | ' | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
PUCO Ordered 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reliability Pricing Model Rate per MW Day in Effect from June 2014 Through May 2015 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 148 | ' | ' | 148 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Retail Stability Rider through May 2014 ($ Per MWh) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 3.5 | ' | ' | 3.5 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs for the Period June 2014 through May 2015 ($ per MWh) | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1 | ' | ' | 1 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 November 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% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Return on Equity on Capital Costs for Certain Riders | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.65% | ' | ' | 10.65% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Estimated Average Decrease in Customer Rates Over Three Years | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.00% | ' | ' | 9.00% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Intended Retail Stability Rider Rate To Be Continued Until Capacity Deferral Balance Is Collected | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 4 | ' | ' | 4 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Recommended Amount of Storm Cost Recovery as Approved in Stipulation Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55,000,000 | 55,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Reduction in the 2012 Storm Expenses as Approved in the Stipulation Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 6,000,000 | 6,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Net Favorable Fuel Adjustment Recorded in 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Proposed in the Stipulation Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49,000,000 | ' | 49,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 39,000,000 | ' | 39,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | ' | 10,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount of Remaining Foregone Revenues Objected to by an Intervenor | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | ' | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Property, Plant and Equipment, Net | ' | ' | 334,000,000 | 247,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 334,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 86,000,000 | ' | 86,000,000 | ' | ' | ' | ' | ' | ' |
Reversal of Previously Recorded Regulatory Disallowances | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 114,000,000 | ' | 114,000,000 | ' | ' | ' | ' | ' | ' | ' |
Resulting Approved Base Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 52,000,000 | ' | 52,000,000 | ' | ' | ' | ' | ' | ' | ' |
Requested Transmission Cost Recovery Factor Revenue | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10,000,000 | 10,000,000 | ' | ' | ' | ' |
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% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Annual Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 5,000,000 | 5,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Additional Requested Annual Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 15,000,000 | 15,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Total Annual Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 20,000,000 | 20,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed Base Rate Surcharge | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 113,000,000 | 113,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 Increase In Virginia Transmission Rate Adjustment Clause Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | 50,000,000 |
Annual Revenue Increase as Approved in Stipulation Agreement | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 49,000,000 | 49,000,000 |
Approved Return On Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.20% | 10.20% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.90% | 10.90% | ' | ' |
Requested Annual Amortization of Certain Deferred Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | 7,000,000 | ' | ' |
Requested Base Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 38,000,000 | ' | ' | ' | 38,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Requested Return on Equity | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 10.50% | ' | ' | ' | 10.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Proposed Depreciation Increase Included in Requested Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 29,000,000 | ' | ' | ' | 29,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Year One Revenues Related to Proposed Recovery of Advanced Metering Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 7,000,000 | ' | ' | ' | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Year Three Revenues Related to Proposed Recovery of Advanced Metering Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 28,000,000 | ' | ' | ' | 28,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Intervenor Recommended Reduction to the Requested Increase in Annual Base Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 16,000,000 | ' | ' | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Intervenor Recommended Reduction in Annual Base Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 22,000,000 | ' | ' | ' | 22,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Intervenor Recommended Return on Common Equity Range | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 9.18% | 9.50% | ' | ' | 9.18% | 9.50% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Approved Base Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 85,000,000 | 85,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Revised Approved Base Rate Increase | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 92,000,000 | 92,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Projected Capital Costs | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 1,200,000,000 | 1,200,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 60,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Construction Work in Progress | 2,836,000,000 | 2,471,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 217,713,000 | 184,701,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 309,200,000 | 281,849,000 | ' | ' | ' | ' | ' | ' | ' | ' | 188,636,000 | 185,428,000 | ' | ' | ' | ' | ' | ' | ' | ' | 172,949,000 | 175,890,000 | ' | ' | ' | ' | ' | ' | 476,734,000 | 427,164,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 405,000,000 | 405,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Amount Excluded from Indiana Utility Regulatory Commission LCM Project Approval | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 23,000,000 | 23,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Asset Impairments and Other Related Charges | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | $33,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commitments_Guarantees_and_Con2
Commitments, Guarantees and Contingencies (Details) (USD $) | 3 Months Ended |
Mar. 31, 2014 | |
Letters of Credit [Member] | ' |
Maximum Future Payments for Letters of Credit [Abstract] | ' |
Maximum Future Payments for Letters of Credit | $130,000,000 |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | ' |
Variable Rate PCBs Supported | 352,000,000 |
Bilateral Letters of Credit | 356,000,000 |
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 | 130,000,000 |
Uncommitted Facility | 85,000,000 |
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility | 75,000,000 |
Variable Rate PCBs Supported | 352,000,000 |
Bilateral Letters of Credit | 356,000,000 |
Master Lease Agreements [Member] | ' |
Maximum Potential Loss on Master Lease Agreements [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 21,000,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 21,000,000 |
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 | 62,000,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 16,000,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 46,000,000 |
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 | 2,580,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 2,580,000 |
Future Minimum Lease Obligation for Remaining Railcars | 13,000,000 |
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] | Master Lease Agreements [Member] | ' |
Maximum Potential Loss on Master Lease Agreements [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 2,486,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 2,486,000 |
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 | 62,000,000 |
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent | 16,000,000 |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 46,000,000 |
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 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Maximum Future Payments for Letters of Credit | 3,081,000 |
Ohio Power Co [Member] | Master Lease Agreements [Member] | ' |
Maximum Potential Loss on Master Lease Agreements [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 4,384,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 4,384,000 |
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 | 3,772,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 3,772,000 |
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 | 1,347,000 |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Max Potential Loss on Master Lease Agreements | 1,347,000 |
Superfund and State Remediation [Member] | ' |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Expense Recorded Due to Remediation Work Remaining Provision | 8,000,000 |
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member] | ' |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ' |
Expense Recorded Due to Remediation Work Remaining Provision | $8,000,000 |
Acquisitions_Dispositions_and_
Acquisitions Dispositions and Discontinued Operations (Details) (USD $) | 3 Months Ended | ||
In Millions, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 |
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract] | ' | ' | ' |
Acquisitions of Assets | $43 | $2 | ' |
Goodwill | $91 | ' | $91 |
Benefit_Plans_Details
Benefit Plans (Details) (USD $) | 3 Months Ended | |
In Thousands, unless otherwise specified | Mar. 31, 2014 | Mar. 31, 2013 |
Pension Plans [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | $18,000 | $17,000 |
Interest Cost | 55,000 | 50,000 |
Expected Return on Plan Assets | -66,000 | -69,000 |
Amortization of Prior Service Cost (Credit) | 1,000 | 1,000 |
Amortization of Net Actuarial Loss | 31,000 | 46,000 |
Net Periodic Benefit Cost (Credit) | 39,000 | 45,000 |
Pension Plans [Member] | Appalachian Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 1,759 | 1,543 |
Interest Cost | 7,406 | 6,916 |
Expected Return on Plan Assets | -8,482 | -9,260 |
Amortization of Prior Service Cost (Credit) | 50 | 49 |
Amortization of Net Actuarial Loss | 4,148 | 6,256 |
Net Periodic Benefit Cost (Credit) | 4,881 | 5,504 |
Pension Plans [Member] | Indiana Michigan Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 2,517 | 2,184 |
Interest Cost | 6,573 | 6,025 |
Expected Return on Plan Assets | -7,748 | -8,207 |
Amortization of Prior Service Cost (Credit) | 49 | 49 |
Amortization of Net Actuarial Loss | 3,646 | 5,422 |
Net Periodic Benefit Cost (Credit) | 5,037 | 5,473 |
Pension Plans [Member] | Ohio Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 1,285 | 2,372 |
Interest Cost | 5,526 | 10,292 |
Expected Return on Plan Assets | -6,607 | -15,141 |
Amortization of Prior Service Cost (Credit) | 39 | 71 |
Amortization of Net Actuarial Loss | 3,106 | 9,309 |
Net Periodic Benefit Cost (Credit) | 3,349 | 6,903 |
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 1,302 | 1,391 |
Interest Cost | 3,014 | 2,748 |
Expected Return on Plan Assets | -3,651 | -3,918 |
Amortization of Prior Service Cost (Credit) | 74 | 74 |
Amortization of Net Actuarial Loss | 1,688 | 2,461 |
Net Periodic Benefit Cost (Credit) | 2,427 | 2,756 |
Pension Plans [Member] | Southwestern Electric Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 1,655 | 1,753 |
Interest Cost | 3,163 | 2,864 |
Expected Return on Plan Assets | -3,857 | -4,127 |
Amortization of Prior Service Cost (Credit) | 87 | 87 |
Amortization of Net Actuarial Loss | 1,761 | 2,553 |
Net Periodic Benefit Cost (Credit) | 2,809 | 3,130 |
Other Postretirement Benefit Plans [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 4,000 | 6,000 |
Interest Cost | 17,000 | 18,000 |
Expected Return on Plan Assets | -28,000 | -27,000 |
Amortization of Prior Service Cost (Credit) | -17,000 | -17,000 |
Amortization of Net Actuarial Loss | 5,000 | 16,000 |
Net Periodic Benefit Cost (Credit) | -19,000 | -4,000 |
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 362 | 641 |
Interest Cost | 3,197 | 3,363 |
Expected Return on Plan Assets | -4,633 | -4,536 |
Amortization of Prior Service Cost (Credit) | -2,513 | -2,512 |
Amortization of Net Actuarial Loss | 1,146 | 3,062 |
Net Periodic Benefit Cost (Credit) | -2,441 | 18 |
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 487 | 805 |
Interest Cost | 1,909 | 2,055 |
Expected Return on Plan Assets | -3,364 | -3,296 |
Amortization of Prior Service Cost (Credit) | -2,355 | -2,355 |
Amortization of Net Actuarial Loss | 592 | 1,882 |
Net Periodic Benefit Cost (Credit) | -2,731 | -909 |
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 256 | 1,300 |
Interest Cost | 1,901 | 4,447 |
Expected Return on Plan Assets | -3,380 | -6,238 |
Amortization of Prior Service Cost (Credit) | -1,731 | -3,231 |
Amortization of Net Actuarial Loss | 595 | 4,041 |
Net Periodic Benefit Cost (Credit) | -2,359 | 319 |
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 210 | 343 |
Interest Cost | 893 | 948 |
Expected Return on Plan Assets | -1,575 | -1,522 |
Amortization of Prior Service Cost (Credit) | -1,072 | -1,072 |
Amortization of Net Actuarial Loss | 277 | 869 |
Net Periodic Benefit Cost (Credit) | -1,267 | -434 |
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | ' | ' |
Components of Net Periodic Benefit Cost | ' | ' |
Service Cost | 253 | 423 |
Interest Cost | 998 | 1,075 |
Expected Return on Plan Assets | -1,754 | -1,720 |
Amortization of Prior Service Cost (Credit) | -1,289 | -1,288 |
Amortization of Net Actuarial Loss | 309 | 982 |
Net Periodic Benefit Cost (Credit) | ($1,483) | ($528) |
Business_Segments_Details
Business Segments (Details) (USD $) | 3 Months Ended | |||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||||
Reportable Segment Information | ' | ' | ' | |||
Revenues | $4,648,000,000 | $3,826,000,000 | ' | |||
Net Income (Loss) | 561,000,000 | 364,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 61,094,000,000 | ' | 60,285,000,000 | |||
Accumulated Depreciation and Amortization | 19,564,000,000 | ' | 19,288,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 41,530,000,000 | ' | 40,997,000,000 | |||
Total Assets | 57,038,000,000 | ' | 56,414,000,000 | |||
Reconciling Adjustments [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Net Income (Loss) | 0 | 0 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | -272,000,000 | [1] | ' | -269,000,000 | [1] | |
Accumulated Depreciation and Amortization | -88,000,000 | [1] | ' | -85,000,000 | [1] | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | -184,000,000 | [1] | ' | -184,000,000 | [1] | |
Total Assets | -19,606,000,000 | [1],[2] | ' | -19,531,000,000 | [1],[2] | |
Vertically Integrated Utilities [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 2,549,000,000 | [3] | 2,356,000,000 | ' | ||
Revenues | 2,586,000,000 | 2,515,000,000 | ' | |||
Net Income (Loss) | 279,000,000 | 181,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 37,923,000,000 | ' | 37,545,000,000 | |||
Accumulated Depreciation and Amortization | 12,424,000,000 | ' | 12,250,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 25,499,000,000 | ' | 25,295,000,000 | |||
Total Assets | 32,997,000,000 | ' | 32,791,000,000 | |||
Vertically Integrated Utilities [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 37,000,000 | [3] | 159,000,000 | ' | ||
Transmission And Distribution Utilities [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 1,161,000,000 | 1,090,000,000 | ' | |||
Revenues | 1,215,000,000 | 1,134,000,000 | ' | |||
Net Income (Loss) | 97,000,000 | 87,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 12,339,000,000 | ' | 12,143,000,000 | |||
Accumulated Depreciation and Amortization | 3,382,000,000 | ' | 3,342,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 8,957,000,000 | ' | 8,801,000,000 | |||
Total Assets | 13,899,000,000 | ' | 14,165,000,000 | |||
Transmission And Distribution Utilities [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 54,000,000 | 44,000,000 | ' | |||
AEP Transmission Holdco [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 12,000,000 | 3,000,000 | ' | |||
Revenues | 28,000,000 | 8,000,000 | ' | |||
Net Income (Loss) | 24,000,000 | 12,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 1,842,000,000 | ' | 1,636,000,000 | |||
Accumulated Depreciation and Amortization | 13,000,000 | ' | 10,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 1,829,000,000 | ' | 1,626,000,000 | |||
Total Assets | 2,460,000,000 | ' | 2,245,000,000 | |||
AEP Transmission Holdco [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 16,000,000 | 5,000,000 | ' | |||
AEP River Operations [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 146,000,000 | 128,000,000 | ' | |||
Revenues | 165,000,000 | 133,000,000 | ' | |||
Net Income (Loss) | 3,000,000 | -2,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 639,000,000 | ' | 638,000,000 | |||
Accumulated Depreciation and Amortization | 197,000,000 | ' | 189,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 442,000,000 | ' | 449,000,000 | |||
Total Assets | 659,000,000 | ' | 673,000,000 | |||
AEP River Operations [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 19,000,000 | 5,000,000 | ' | |||
Generation and Marketing [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 821,000,000 | [3] | 258,000,000 | ' | ||
Revenues | 1,251,000,000 | 920,000,000 | ' | |||
Net Income (Loss) | 163,000,000 | 85,000,000 | ' | |||
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 8,302,000,000 | ' | 8,277,000,000 | |||
Accumulated Depreciation and Amortization | 3,460,000,000 | ' | 3,409,000,000 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 4,842,000,000 | ' | 4,868,000,000 | |||
Total Assets | 6,354,000,000 | ' | 6,426,000,000 | |||
Generation and Marketing [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 430,000,000 | [3] | 662,000,000 | ' | ||
All Other [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 10,000,000 | [4] | 5,000,000 | [4] | ' | |
Revenues | 26,000,000 | [4] | 18,000,000 | [4] | ' | |
Net Income (Loss) | -5,000,000 | [4] | 1,000,000 | [4] | ' | |
Balance Sheet Information | ' | ' | ' | |||
Total Property, Plant and Equipment | 321,000,000 | [4] | ' | 315,000,000 | [4] | |
Accumulated Depreciation and Amortization | 176,000,000 | [4] | ' | 173,000,000 | [4] | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 145,000,000 | [4] | ' | 142,000,000 | [4] | |
Total Assets | 20,275,000,000 | [4] | ' | 19,645,000,000 | [4] | |
All Other [Member] | Significant Reconciling Items [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | 16,000,000 | [4] | 13,000,000 | [4] | ' | |
Consolidation Eliminations [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | -51,000,000 | [5] | -14,000,000 | [5] | ' | |
Revenues | -623,000,000 | -902,000,000 | ' | |||
Consolidation Eliminations [Member] | Reconciling Adjustments [Member] | ' | ' | ' | |||
Reportable Segment Information | ' | ' | ' | |||
Sales Revenue, Net | ($572,000,000) | ($888,000,000) | ' | |||
[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 AEPbs investments in subsidiary companies. | |||||
[3] | Includes the impact of the corporate separation of OPCobs generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. | |||||
[4] | Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parentbs guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | |||||
[5] | Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation. |
Derivatives_and_Hedging_Detail
Derivatives and Hedging (Details) (USD $) | 3 Months Ended | 12 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | $19,000,000 | ' | $4,000,000 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 17,000,000 | ' | 13,000,000 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 125,000,000 | ' | 160,000,000 | |||
Long-term Risk Management Assets | 266,000,000 | ' | 297,000,000 | |||
Total Assets | 391,000,000 | ' | 457,000,000 | |||
Current Risk Management Liabilities | 60,000,000 | ' | 90,000,000 | |||
Long-term Risk Management Liabilities | 137,000,000 | ' | 177,000,000 | |||
Total Liabilities | 197,000,000 | ' | 267,000,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 139,000,000 | 18,000,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 13,000,000 | [1] | ' | 7,000,000 | [1] | |
Hedging Liabilities | 7,000,000 | [1] | ' | 8,000,000 | [1] | |
AOCI Gain (Loss) Net of Tax | -18,000,000 | ' | -23,000,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -1,000,000 | ' | -4,000,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '41 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 2,000,000 | ' | 3,000,000 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 144,000,000 | ' | 33,000,000 | |||
Amount Attributable to RTO and ISO Activities | 38,000,000 | ' | 28,000,000 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 225,000,000 | ' | 293,000,000 | |||
Amount of Cash Collateral Posted | 0 | ' | 1,000,000 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 177,000,000 | ' | 235,000,000 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 19,000,000 | ' | 4,000,000 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 17,000,000 | ' | 13,000,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '41 months | ' | ' | |||
Gain (Loss) on Fair Value Hedging Instrument | 2,000,000 | -1,000,000 | ' | |||
Gain (Loss) on Fair Value Portion of Long Term Debt | -2,000,000 | 1,000,000 | ' | |||
Appalachian Power Co [Member] | ' | ' | ' | |||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 32,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 1,362,000 | ' | 2,993,000 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 15,972,000 | ' | 21,171,000 | |||
Long-term Risk Management Assets | 14,013,000 | ' | 16,948,000 | |||
Total Assets | 29,985,000 | ' | 38,119,000 | |||
Current Risk Management Liabilities | 4,636,000 | ' | 8,892,000 | |||
Long-term Risk Management Liabilities | 7,929,000 | ' | 10,241,000 | |||
Total Liabilities | 12,565,000 | ' | 19,133,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 37,183,000 | 213,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '2 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 285,000 | ' | 575,000 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 5,254,000 | ' | 2,747,000 | |||
Amount Attributable to RTO and ISO Activities | 4,774,000 | ' | 2,539,000 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 16,375,000 | ' | 19,648,000 | |||
Amount of Cash Collateral Posted | 0 | ' | 0 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 12,865,000 | ' | 18,568,000 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 32,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 1,362,000 | ' | 2,993,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '2 months | ' | ' | |||
Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 21,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 924,000 | ' | 2,030,000 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 12,558,000 | ' | 15,388,000 | |||
Long-term Risk Management Assets | 9,505,000 | ' | 11,495,000 | |||
Total Assets | 22,063,000 | ' | 26,883,000 | |||
Current Risk Management Liabilities | 4,134,000 | ' | 7,029,000 | |||
Long-term Risk Management Liabilities | 5,378,000 | ' | 6,946,000 | |||
Total Liabilities | 9,512,000 | ' | 13,975,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 24,252,000 | 251,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '2 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 190,000 | ' | 390,000 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 3,560,000 | ' | 1,863,000 | |||
Amount Attributable to RTO and ISO Activities | 3,238,000 | ' | 1,722,000 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 11,107,000 | ' | 13,326,000 | |||
Amount of Cash Collateral Posted | 0 | ' | 0 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 8,726,000 | ' | 12,594,000 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 21,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 924,000 | ' | 2,030,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '2 months | ' | ' | |||
Ohio Power Co [Member] | ' | ' | ' | |||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 3,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 0 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 3,980,000 | ' | 3,082,000 | |||
Total Assets | ' | ' | 3,082,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 35,099,000 | 509,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 78,000 | ' | 349,000 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 0 | ' | 0 | |||
Amount Attributable to RTO and ISO Activities | 0 | ' | 0 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 0 | ' | 0 | |||
Amount of Cash Collateral Posted | 0 | ' | 0 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | ' | 0 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 3,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 0 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 1,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 1,000 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 1,349,000 | ' | 1,167,000 | |||
Total Assets | ' | ' | 1,167,000 | |||
Current Risk Management Liabilities | 83,000 | ' | 85,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 767,000 | 2,058,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 132,000 | ' | 0 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 4,156,000 | ' | 2,930,000 | |||
Amount Attributable to RTO and ISO Activities | 0 | ' | 410,000 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 0 | ' | 3,000 | |||
Amount of Cash Collateral Posted | 0 | ' | 0 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | ' | 3,000 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 1,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 1,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Cash Collateral Netting | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 2,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 3,000 | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 1,907,000 | ' | 1,179,000 | |||
Total Assets | ' | ' | 1,179,000 | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1,356,000 | 395,000 | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Collateral Triggering Events [Abstract] | ' | ' | ' | |||
Liabilities for Derivative Contracts with Credit Downgrade Triggers | 167,000 | ' | 0 | |||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post | 145,000 | ' | 713,000 | |||
Amount Attributable to RTO and ISO Activities | 0 | ' | 519,000 | |||
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements | 0 | ' | 3,000 | |||
Amount of Cash Collateral Posted | 0 | ' | 0 | |||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | ' | 3,000 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cash Collateral Received Netted Against Risk Management Assets | 2,000 | ' | 0 | |||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | ' | 3,000 | |||
Maximum Term for Exposure to Variability of Future Cash Flows | '0 months | ' | ' | |||
Risk Management Contracts [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 370,000,000 | [2],[3] | ' | 440,000,000 | [2],[4] | |
Total Liabilities | 178,000,000 | [2],[3] | ' | 245,000,000 | [2],[4] | |
Risk Management Contracts [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 29,776,000 | [2],[5] | ' | 37,756,000 | [2],[5] | |
Total Liabilities | 12,490,000 | [2],[5] | ' | 18,846,000 | [2],[5] | |
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 21,921,000 | [2],[5] | ' | 26,667,000 | [2],[5] | |
Total Liabilities | 9,461,000 | [2],[5] | ' | 13,781,000 | [2],[5] | |
Risk Management Contracts [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 3,980,000 | [2],[5] | ' | 2,920,000 | [2],[5] | |
Total Liabilities | 0 | [2],[5] | ' | 0 | [2],[5] | |
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 1,349,000 | [2],[5] | ' | 1,083,000 | [2],[5] | |
Total Liabilities | 83,000 | [2],[5] | ' | 85,000 | [2],[5] | |
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Total Assets | 1,907,000 | [2],[5] | ' | 1,082,000 | [2],[5] | |
Total Liabilities | 0 | [2],[5] | ' | 0 | [2],[5] | |
Commodity [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 13,000,000 | [1] | ' | 7,000,000 | [1] | |
Hedging Liabilities | 5,000,000 | [1] | ' | 6,000,000 | [1] | |
AOCI Gain (Loss) Net of Tax | 4,000,000 | ' | 0 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 3,000,000 | ' | 0 | |||
Derivatives and Hedging (Textuals) [Abstract] | ' | ' | ' | |||
Cross Default Provisions Maximum Third Party Obligation Amount | 50,000,000 | ' | 50,000,000 | |||
Commodity [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 209,000 | [1] | ' | 363,000 | [1] | |
Hedging Liabilities | 75,000 | [1] | ' | 287,000 | [1] | |
AOCI Gain (Loss) Net of Tax | 87,000 | ' | 94,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 87,000 | ' | 94,000 | |||
Commodity [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 142,000 | [1] | ' | 216,000 | [1] | |
Hedging Liabilities | 51,000 | [1] | ' | 194,000 | [1] | |
AOCI Gain (Loss) Net of Tax | 61,000 | ' | 46,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 61,000 | ' | 46,000 | |||
Commodity [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 162,000 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 0 | ' | 105,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | ' | 105,000 | |||
Commodity [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 84,000 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 0 | ' | 57,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | ' | 57,000 | |||
Commodity [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 97,000 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 0 | ' | 66,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0 | ' | 66,000 | |||
Commodity [Member] | Risk Management Contracts [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 442,000,000 | [6] | ' | 347,000,000 | [6] | |
Long-term Risk Management Assets | 342,000,000 | [6] | ' | 368,000,000 | [6] | |
Total Assets | 784,000,000 | [6] | ' | 715,000,000 | [6] | |
Current Risk Management Liabilities | 384,000,000 | [6] | ' | 292,000,000 | [6] | |
Long-term Risk Management Liabilities | 205,000,000 | [6] | ' | 237,000,000 | [6] | |
Total Liabilities | 589,000,000 | [6] | ' | 529,000,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 195,000,000 | [6] | ' | 186,000,000 | [6] | |
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 34,483,000 | [6] | ' | 46,431,000 | [6] | |
Long-term Risk Management Assets | 17,304,000 | [6] | ' | 20,948,000 | [6] | |
Total Assets | 51,787,000 | [6] | ' | 67,379,000 | [6] | |
Current Risk Management Liabilities | 24,273,000 | [6] | ' | 37,010,000 | [6] | |
Long-term Risk Management Liabilities | 11,558,000 | [6] | ' | 14,452,000 | [6] | |
Total Liabilities | 35,831,000 | [6] | ' | 51,462,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 15,956,000 | [6] | ' | 15,917,000 | [6] | |
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 26,273,000 | [6] | ' | 33,229,000 | [6] | |
Long-term Risk Management Assets | 11,737,000 | [6] | ' | 14,208,000 | [6] | |
Total Assets | 38,010,000 | [6] | ' | 47,437,000 | [6] | |
Current Risk Management Liabilities | 18,614,000 | [6] | ' | 26,779,000 | [6] | |
Long-term Risk Management Liabilities | 7,839,000 | [6] | ' | 9,802,000 | [6] | |
Total Liabilities | 26,453,000 | [6] | ' | 36,581,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 11,557,000 | [6] | ' | 10,856,000 | [6] | |
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 4,066,000 | [6] | ' | 3,269,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 4,066,000 | [6] | ' | 3,269,000 | [6] | |
Current Risk Management Liabilities | 83,000 | [6] | ' | 349,000 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 83,000 | [6] | ' | 349,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 3,983,000 | [6] | ' | 2,920,000 | [6] | |
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 1,403,000 | [6] | ' | 1,078,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 1,403,000 | [6] | ' | 1,078,000 | [6] | |
Current Risk Management Liabilities | 136,000 | [6] | ' | 81,000 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 136,000 | [6] | ' | 81,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,267,000 | [6] | ' | 997,000 | [6] | |
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 2,080,000 | [6] | ' | 1,233,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 2,080,000 | [6] | ' | 1,233,000 | [6] | |
Current Risk Management Liabilities | 171,000 | [6] | ' | 154,000 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 171,000 | [6] | ' | 154,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,909,000 | [6] | ' | 1,079,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 23,000,000 | [6] | ' | 12,000,000 | [6] | |
Long-term Risk Management Assets | 5,000,000 | [6] | ' | 3,000,000 | [6] | |
Total Assets | 28,000,000 | [6] | ' | 15,000,000 | [6] | |
Current Risk Management Liabilities | 16,000,000 | [6] | ' | 11,000,000 | [6] | |
Long-term Risk Management Liabilities | 4,000,000 | [6] | ' | 3,000,000 | [6] | |
Total Liabilities | 20,000,000 | [6] | ' | 14,000,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 8,000,000 | [6] | ' | 1,000,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 224,000 | [6] | ' | 389,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 224,000 | [6] | ' | 389,000 | [6] | |
Current Risk Management Liabilities | 90,000 | [6] | ' | 313,000 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 90,000 | [6] | ' | 313,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 134,000 | [6] | ' | 76,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 152,000 | [6] | ' | 234,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 152,000 | [6] | ' | 234,000 | [6] | |
Current Risk Management Liabilities | 61,000 | [6] | ' | 212,000 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 61,000 | [6] | ' | 212,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 91,000 | [6] | ' | 22,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 0 | [6] | ' | 162,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 162,000 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | ' | 162,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 0 | [6] | ' | 84,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 84,000 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | ' | 84,000 | [6] | |
Commodity [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 0 | [6] | ' | 97,000 | [6] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 97,000 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | ' | 97,000 | [6] | |
Interest Rate and Foreign Currency [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 819,000,000 | ' | 820,000,000 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 2,000,000 | [1] | ' | 2,000,000 | [1] | |
AOCI Gain (Loss) Net of Tax | -22,000,000 | ' | -23,000,000 | |||
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 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 3,343,000 | ' | 3,090,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -682,000 | ' | -806,000 | |||
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | -15,566,000 | ' | -15,976,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | -1,426,000 | ' | -1,568,000 | |||
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 6,631,000 | ' | 6,974,000 | |||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1,372,000 | ' | 1,363,000 | |||
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | 5,512,000 | ' | 5,701,000 | |||
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 | |||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | ' | ' | ' | |||
Hedging Assets | 0 | [1] | ' | 0 | [1] | |
Hedging Liabilities | 0 | [1] | ' | 0 | [1] | |
AOCI Gain (Loss) Net of Tax | -12,736,000 | ' | -13,304,000 | |||
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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 4,000,000 | [6] | ' | 4,000,000 | [6] | |
Current Risk Management Liabilities | 1,000,000 | [6] | ' | 1,000,000 | [6] | |
Long-term Risk Management Liabilities | 13,000,000 | [6] | ' | 15,000,000 | [6] | |
Total Liabilities | 14,000,000 | [6] | ' | 16,000,000 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | -10,000,000 | [6] | ' | -12,000,000 | [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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 0 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 0 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | ' | 0 | [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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 0 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 0 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 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] | |
Long-term Risk Management Assets | 0 | [6] | ' | 0 | [6] | |
Total Assets | 0 | [6] | ' | 0 | [6] | |
Current Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Long-term Risk Management Liabilities | 0 | [6] | ' | 0 | [6] | |
Total Liabilities | 0 | [6] | ' | 0 | [6] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 0 | [6] | ' | 0 | [6] | |
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 469,000,000 | ' | 363,000,000 | |||
Long-term Risk Management Assets | 347,000,000 | ' | 371,000,000 | |||
Total Assets | 816,000,000 | ' | 734,000,000 | |||
Current Risk Management Liabilities | 401,000,000 | ' | 304,000,000 | |||
Long-term Risk Management Liabilities | 222,000,000 | ' | 255,000,000 | |||
Total Liabilities | 623,000,000 | ' | 559,000,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 193,000,000 | ' | 175,000,000 | |||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 34,707,000 | ' | 46,820,000 | |||
Long-term Risk Management Assets | 17,304,000 | ' | 20,948,000 | |||
Total Assets | 52,011,000 | ' | 67,768,000 | |||
Current Risk Management Liabilities | 24,363,000 | ' | 37,323,000 | |||
Long-term Risk Management Liabilities | 11,558,000 | ' | 14,452,000 | |||
Total Liabilities | 35,921,000 | ' | 51,775,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 16,090,000 | ' | 15,993,000 | |||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 26,425,000 | ' | 33,463,000 | |||
Long-term Risk Management Assets | 11,737,000 | ' | 14,208,000 | |||
Total Assets | 38,162,000 | ' | 47,671,000 | |||
Current Risk Management Liabilities | 18,675,000 | ' | 26,991,000 | |||
Long-term Risk Management Liabilities | 7,839,000 | ' | 9,802,000 | |||
Total Liabilities | 26,514,000 | ' | 36,793,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 11,648,000 | ' | 10,878,000 | |||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 4,066,000 | ' | 3,431,000 | |||
Long-term Risk Management Assets | 0 | ' | 0 | |||
Total Assets | 4,066,000 | ' | 3,431,000 | |||
Current Risk Management Liabilities | 83,000 | ' | 349,000 | |||
Long-term Risk Management Liabilities | 0 | ' | 0 | |||
Total Liabilities | 83,000 | ' | 349,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 3,983,000 | ' | 3,082,000 | |||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 1,403,000 | ' | 1,162,000 | |||
Long-term Risk Management Assets | 0 | ' | 0 | |||
Total Assets | 1,403,000 | ' | 1,162,000 | |||
Current Risk Management Liabilities | 136,000 | ' | 81,000 | |||
Long-term Risk Management Liabilities | 0 | ' | 0 | |||
Total Liabilities | 136,000 | ' | 81,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 1,267,000 | ' | 1,081,000 | |||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 2,080,000 | ' | 1,330,000 | |||
Long-term Risk Management Assets | 0 | ' | 0 | |||
Total Assets | 2,080,000 | ' | 1,330,000 | |||
Current Risk Management Liabilities | 171,000 | ' | 154,000 | |||
Long-term Risk Management Liabilities | 0 | ' | 0 | |||
Total Liabilities | 171,000 | ' | 154,000 | |||
Total MTM Derivative Contract Net Assets (Liabilities) | 1,909,000 | ' | 1,176,000 | |||
Gross Amounts Offset in the Statement of Financial Position [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | -344,000,000 | [7] | ' | -203,000,000 | [7] | |
Long-term Risk Management Assets | -81,000,000 | [7] | ' | -74,000,000 | [7] | |
Total Assets | -425,000,000 | [7] | ' | -277,000,000 | [7] | |
Current Risk Management Liabilities | -341,000,000 | [7] | ' | -214,000,000 | [7] | |
Long-term Risk Management Liabilities | -85,000,000 | [7] | ' | -78,000,000 | [7] | |
Total Liabilities | -426,000,000 | [7] | ' | -292,000,000 | [7] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,000,000 | [7] | ' | 15,000,000 | [7] | |
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | -18,735,000 | [8] | ' | -25,649,000 | [8] | |
Long-term Risk Management Assets | -3,291,000 | [8] | ' | -4,000,000 | [8] | |
Total Assets | -22,026,000 | [8] | ' | -29,649,000 | [8] | |
Current Risk Management Liabilities | -19,727,000 | [8] | ' | -28,431,000 | [8] | |
Long-term Risk Management Liabilities | -3,629,000 | [8] | ' | -4,211,000 | [8] | |
Total Liabilities | -23,356,000 | [8] | ' | -32,642,000 | [8] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,330,000 | [8] | ' | 2,993,000 | [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 | -13,867,000 | [8] | ' | -18,075,000 | [8] | |
Long-term Risk Management Assets | -2,232,000 | [8] | ' | -2,713,000 | [8] | |
Total Assets | -16,099,000 | [8] | ' | -20,788,000 | [8] | |
Current Risk Management Liabilities | -14,541,000 | [8] | ' | -19,962,000 | [8] | |
Long-term Risk Management Liabilities | -2,461,000 | [8] | ' | -2,856,000 | [8] | |
Total Liabilities | -17,002,000 | [8] | ' | -22,818,000 | [8] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 903,000 | [8] | ' | 2,030,000 | [8] | |
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | -86,000 | [8] | ' | -349,000 | [8] | |
Long-term Risk Management Assets | 0 | [8] | ' | 0 | [8] | |
Total Assets | -86,000 | [8] | ' | -349,000 | [8] | |
Current Risk Management Liabilities | -83,000 | [8] | ' | -349,000 | [8] | |
Long-term Risk Management Liabilities | 0 | [8] | ' | 0 | [8] | |
Total Liabilities | -83,000 | [8] | ' | -349,000 | [8] | |
Total MTM Derivative Contract Net Assets (Liabilities) | -3,000 | [8] | ' | 0 | [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 | -54,000 | [8] | ' | 5,000 | [8] | |
Long-term Risk Management Assets | 0 | [8] | ' | 0 | [8] | |
Total Assets | -54,000 | [8] | ' | 5,000 | [8] | |
Current Risk Management Liabilities | -53,000 | [8] | ' | 4,000 | [8] | |
Long-term Risk Management Liabilities | 0 | [8] | ' | 0 | [8] | |
Total Liabilities | -53,000 | [8] | ' | 4,000 | [8] | |
Total MTM Derivative Contract Net Assets (Liabilities) | -1,000 | [8] | ' | 1,000 | [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 | -173,000 | [8] | ' | -151,000 | [8] | |
Long-term Risk Management Assets | 0 | [8] | ' | 0 | [8] | |
Total Assets | -173,000 | [8] | ' | -151,000 | [8] | |
Current Risk Management Liabilities | -171,000 | [8] | ' | -154,000 | [8] | |
Long-term Risk Management Liabilities | 0 | [8] | ' | 0 | [8] | |
Total Liabilities | -171,000 | [8] | ' | -154,000 | [8] | |
Total MTM Derivative Contract Net Assets (Liabilities) | -2,000 | [8] | ' | 3,000 | [8] | |
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | ' | ' | ' | |||
Fair Value of Derivative Instruments | ' | ' | ' | |||
Current Risk Management Assets | 125,000,000 | [9] | ' | 160,000,000 | [9] | |
Long-term Risk Management Assets | 266,000,000 | [9] | ' | 297,000,000 | [9] | |
Total Assets | 391,000,000 | [9] | ' | 457,000,000 | [9] | |
Current Risk Management Liabilities | 60,000,000 | [9] | ' | 90,000,000 | [9] | |
Long-term Risk Management Liabilities | 137,000,000 | [9] | ' | 177,000,000 | [9] | |
Total Liabilities | 197,000,000 | [9] | ' | 267,000,000 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 194,000,000 | [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 | 15,972,000 | [9] | ' | 21,171,000 | [9] | |
Long-term Risk Management Assets | 14,013,000 | [9] | ' | 16,948,000 | [9] | |
Total Assets | 29,985,000 | [9] | ' | 38,119,000 | [9] | |
Current Risk Management Liabilities | 4,636,000 | [9] | ' | 8,892,000 | [9] | |
Long-term Risk Management Liabilities | 7,929,000 | [9] | ' | 10,241,000 | [9] | |
Total Liabilities | 12,565,000 | [9] | ' | 19,133,000 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 17,420,000 | [9] | ' | 18,986,000 | [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 | 12,558,000 | [9] | ' | 15,388,000 | [9] | |
Long-term Risk Management Assets | 9,505,000 | [9] | ' | 11,495,000 | [9] | |
Total Assets | 22,063,000 | [9] | ' | 26,883,000 | [9] | |
Current Risk Management Liabilities | 4,134,000 | [9] | ' | 7,029,000 | [9] | |
Long-term Risk Management Liabilities | 5,378,000 | [9] | ' | 6,946,000 | [9] | |
Total Liabilities | 9,512,000 | [9] | ' | 13,975,000 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 12,551,000 | [9] | ' | 12,908,000 | [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 | 3,980,000 | [9] | ' | 3,082,000 | [9] | |
Long-term Risk Management Assets | 0 | [9] | ' | 0 | [9] | |
Total Assets | 3,980,000 | [9] | ' | 3,082,000 | [9] | |
Current Risk Management Liabilities | 0 | [9] | ' | 0 | [9] | |
Long-term Risk Management Liabilities | 0 | [9] | ' | 0 | [9] | |
Total Liabilities | 0 | [9] | ' | 0 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 3,980,000 | [9] | ' | 3,082,000 | [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 | 1,349,000 | [9] | ' | 1,167,000 | [9] | |
Long-term Risk Management Assets | 0 | [9] | ' | 0 | [9] | |
Total Assets | 1,349,000 | [9] | ' | 1,167,000 | [9] | |
Current Risk Management Liabilities | 83,000 | [9] | ' | 85,000 | [9] | |
Long-term Risk Management Liabilities | 0 | [9] | ' | 0 | [9] | |
Total Liabilities | 83,000 | [9] | ' | 85,000 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,266,000 | [9] | ' | 1,082,000 | [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 | 1,907,000 | [9] | ' | 1,179,000 | [9] | |
Long-term Risk Management Assets | 0 | [9] | ' | 0 | [9] | |
Total Assets | 1,907,000 | [9] | ' | 1,179,000 | [9] | |
Current Risk Management Liabilities | 0 | [9] | ' | 0 | [9] | |
Long-term Risk Management Liabilities | 0 | [9] | ' | 0 | [9] | |
Total Liabilities | 0 | [9] | ' | 0 | [9] | |
Total MTM Derivative Contract Net Assets (Liabilities) | 1,907,000 | [9] | ' | 1,179,000 | [9] | |
Power [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 320,000,000 | ' | 406,000,000 | |||
Power [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 29,680,000 | ' | 48,995,000 | |||
Power [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 19,636,000 | ' | 33,231,000 | |||
Power [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 12,108,000 | ' | 34,843,000 | |||
Power [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 9,251,000 | ' | 13,469,000 | |||
Power [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 11,716,000 | ' | 17,057,000 | |||
Coal [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 4,000,000 | ' | 4,000,000 | |||
Coal [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 186,000 | ' | 31,000 | |||
Coal [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 2,666,000 | ' | 3,389,000 | |||
Coal [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 0 | ' | 0 | |||
Coal [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 750,000 | ' | 1,013,000 | |||
Coal [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Mass Notional Amount | 1,292,000 | ' | 1,692,000 | |||
Natural Gas [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 123,000,000 | ' | 127,000,000 | |||
Natural Gas [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 1,934,000 | ' | 2,477,000 | |||
Natural Gas [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 1,312,000 | ' | 1,680,000 | |||
Natural Gas [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 0 | ' | 0 | |||
Natural Gas [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 0 | ' | 0 | |||
Natural Gas [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Energy Notional Amount | 0 | ' | 0 | |||
Heating Oil and Gasoline [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 4,000,000 | ' | 6,000,000 | |||
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 792,000 | ' | 1,089,000 | |||
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 379,000 | ' | 521,000 | |||
Heating Oil and Gasoline [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 806,000 | ' | 1,108,000 | |||
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 446,000 | ' | 614,000 | |||
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Volume Notional Amount | 508,000 | ' | 699,000 | |||
Interest Rate Contract [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 192,000,000 | ' | 191,000,000 | |||
Interest Rate Contract [Member] | Appalachian Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 10,877,000 | ' | 12,720,000 | |||
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 7,378,000 | ' | 8,627,000 | |||
Interest Rate Contract [Member] | Ohio Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Commodity | ' | ' | ' | |||
Derivative, Notional Amount | 0 | ' | 0 | |||
Vertically Integrated Utilities Revenues [Member] | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 18,000,000 | 6,000,000 | ' | |||
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 | 4,847,000 | 679,000 | ' | |||
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 | 6,156,000 | 4,947,000 | ' | |||
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 | 0 | 1,714,000 | ' | |||
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 | 64,000 | 47,000 | ' | |||
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 | 23,000 | 28,000 | ' | |||
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 | ' | |||
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 | -221,000 | 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 | ' | |||
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 | 221,000 | 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 | ' | |||
Generation And Marketing Revenues [Member] | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 32,000,000 | 16,000,000 | ' | |||
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] | ' | |
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 | 4,000 | [10] | 0 | [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 | 0 | [10] | 486,000 | [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] | -1,205,000 | [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 | 2,000 | [10] | 2,010,000 | [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 | 3,000 | [10] | 271,000 | [10] | ' | |
Regulatory Liabilities [Member] | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | ' | ' | ' | |||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 89,000,000 | [10] | -6,000,000 | [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 | 32,332,000 | [10] | -466,000 | [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 | 18,317,000 | [10] | -5,182,000 | [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 | 35,099,000 | [10] | 0 | [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 | 480,000 | [10] | 1,000 | [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 | $1,330,000 | [10] | $96,000 | [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 March 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||
[4] | The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. 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 | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | $18,087,000,000 | ' | $18,377,000,000 | ||
Long Term Debt, Fair Value | 19,738,000,000 | ' | 19,672,000,000 | ||
Other Temporary Investments | ' | ' | ' | ||
Cost | 299,000,000 | ' | 342,000,000 | ||
Gross Unrealized Gains | 11,000,000 | ' | 11,000,000 | ||
Gross Unrealized Losses | 0 | ' | 0 | ||
Estimated Fair Value | 310,000,000 | ' | 353,000,000 | ||
Debt and Equity Securities Within Other Temporary Investments [Abstract] | ' | ' | ' | ||
Proceeds from Investment Sales | 0 | 0 | ' | ||
Purchases of Investments | 1,000,000 | 11,000,000 | ' | ||
Gross Realized Gains on Investment Sales | 0 | 0 | ' | ||
Gross Realized Losses on Investment Sales | 0 | 0 | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 1,962,000,000 | ' | 1,932,000,000 | ||
Gross Unrealized Gains | 550,000,000 | ' | 535,000,000 | ||
Other-Than-Temporary Impairments | 85,000,000 | ' | 87,000,000 | ||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ' | ' | ' | ||
Proceeds from Investment Sales | 148,000,000 | 168,000,000 | ' | ||
Purchases of Investments | 164,000,000 | 185,000,000 | ' | ||
Gross Realized Gains on Investment Sales | 8,000,000 | 3,000,000 | ' | ||
Gross Realized Losses on Investment Sales | 1,000,000 | 2,000,000 | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 1,962,000,000 | ' | 1,932,000,000 | ||
Fair Value Measurements (Textuals) [Abstract] | ' | ' | ' | ||
Adjusted Cost of Debt Securities | 894,000,000 | ' | 872,000,000 | ||
Adjusted Cost of Domestic Equity Securities | 506,000,000 | ' | 506,000,000 | ||
Appalachian Power Co [Member] | ' | ' | ' | ||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | 4,194,516,000 | ' | 4,194,357,000 | ||
Long Term Debt, Fair Value | 4,730,819,000 | ' | 4,587,079,000 | ||
Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | 2,012,844,000 | ' | 2,039,016,000 | ||
Long Term Debt, Fair Value | 2,203,640,000 | ' | 2,174,891,000 | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 1,962,151,000 | ' | 1,931,610,000 | ||
Gross Unrealized Gains | 549,664,000 | ' | 534,850,000 | ||
Other-Than-Temporary Impairments | 84,626,000 | ' | 86,994,000 | ||
Securities Activity Within Decommissioning and SNF Trusts [Abstract] | ' | ' | ' | ||
Proceeds from Investment Sales | 147,700,000 | 167,670,000 | ' | ||
Purchases of Investments | 164,511,000 | 184,299,000 | ' | ||
Gross Realized Gains on Investment Sales | 8,141,000 | 3,323,000 | ' | ||
Gross Realized Losses on Investment Sales | 874,000 | 2,315,000 | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 1,962,151,000 | ' | 1,931,610,000 | ||
Fair Value Measurements (Textuals) [Abstract] | ' | ' | ' | ||
Adjusted Cost of Debt Securities | 894,000,000 | ' | 872,000,000 | ||
Adjusted Cost of Domestic Equity Securities | 506,000,000 | ' | 506,000,000 | ||
Ohio Power Co [Member] | ' | ' | ' | ||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | 2,510,285,000 | ' | 2,735,175,000 | ||
Long Term Debt, Fair Value | 2,869,364,000 | ' | 3,007,191,000 | ||
Public Service Co Of Oklahoma [Member] | ' | ' | ' | ||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | 1,049,793,000 | ' | 999,810,000 | ||
Long Term Debt, Fair Value | 1,200,741,000 | ' | 1,111,149,000 | ||
Southwestern Electric Power Co [Member] | ' | ' | ' | ||
Book Values and Fair Values of Long - term Debt | ' | ' | ' | ||
Total Long-term Debt Outstanding | 2,041,796,000 | ' | 2,043,332,000 | ||
Long Term Debt, Fair Value | 2,277,262,000 | ' | 2,214,730,000 | ||
Cash [Member] | ' | ' | ' | ||
Other Temporary Investments | ' | ' | ' | ||
Cost | 206,000,000 | ' | 250,000,000 | ||
Gross Unrealized Gains | 0 | ' | 0 | ||
Gross Unrealized Losses | 0 | ' | 0 | ||
Estimated Fair Value | 206,000,000 | [1] | ' | 250,000,000 | [1] |
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 12,000,000 | [2] | ' | 19,000,000 | [2] |
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 12,000,000 | [2] | ' | 19,000,000 | [2] |
Cash [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 12,439,000 | [3] | ' | 18,804,000 | [3] |
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 12,439,000 | [3] | ' | 18,804,000 | [3] |
Fixed Income Funds [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 930,000,000 | ' | 901,000,000 | ||
Gross Unrealized Gains | 36,000,000 | ' | 29,000,000 | ||
Other-Than-Temporary Impairments | 5,000,000 | ' | 5,000,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 930,000,000 | ' | 901,000,000 | ||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 929,567,000 | ' | 900,295,000 | ||
Gross Unrealized Gains | 35,861,000 | ' | 29,312,000 | ||
Other-Than-Temporary Impairments | 5,063,000 | ' | 5,317,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 929,567,000 | ' | 900,295,000 | ||
Mutual Funds Fixed Income [Member] | ' | ' | ' | ||
Other Temporary Investments | ' | ' | ' | ||
Cost | 80,000,000 | ' | 80,000,000 | ||
Gross Unrealized Gains | 0 | ' | 0 | ||
Gross Unrealized Losses | 0 | ' | 0 | ||
Estimated Fair Value | 80,000,000 | ' | 80,000,000 | ||
Domestic [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 1,020,000,000 | [4] | ' | 1,012,000,000 | [4] |
Gross Unrealized Gains | 514,000,000 | ' | 506,000,000 | ||
Other-Than-Temporary Impairments | 80,000,000 | ' | 82,000,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 1,020,000,000 | [4] | ' | 1,012,000,000 | [4] |
Domestic [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 1,020,145,000 | [4] | ' | 1,012,511,000 | [4] |
Gross Unrealized Gains | 513,803,000 | ' | 505,538,000 | ||
Other-Than-Temporary Impairments | 79,563,000 | ' | 81,677,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 1,020,145,000 | [4] | ' | 1,012,511,000 | [4] |
Mutual Funds Equity [Member] | ' | ' | ' | ||
Other Temporary Investments | ' | ' | ' | ||
Cost | 13,000,000 | ' | 12,000,000 | ||
Gross Unrealized Gains | 11,000,000 | ' | 11,000,000 | ||
Gross Unrealized Losses | 0 | ' | 0 | ||
Estimated Fair Value | 24,000,000 | [4] | ' | 23,000,000 | [4] |
Cash and Cash Equivalents [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 12,000,000 | ' | 19,000,000 | ||
Gross Unrealized Gains | 0 | ' | 0 | ||
Other-Than-Temporary Impairments | 0 | ' | 0 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 12,000,000 | ' | 19,000,000 | ||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 12,439,000 | ' | 18,804,000 | ||
Gross Unrealized Gains | 0 | ' | 0 | ||
Other-Than-Temporary Impairments | 0 | ' | 0 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 12,439,000 | ' | 18,804,000 | ||
US Government Agencies Debt Securities [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 606,000,000 | ' | 609,000,000 | ||
Gross Unrealized Gains | 31,000,000 | ' | 26,000,000 | ||
Other-Than-Temporary Impairments | 4,000,000 | ' | 4,000,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 606,000,000 | ' | 609,000,000 | ||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 606,228,000 | ' | 608,875,000 | ||
Gross Unrealized Gains | 31,666,000 | ' | 26,114,000 | ||
Other-Than-Temporary Impairments | 3,621,000 | ' | 3,824,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 606,228,000 | ' | 608,875,000 | ||
Corporate Debt [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 43,000,000 | ' | 37,000,000 | ||
Gross Unrealized Gains | 4,000,000 | ' | 2,000,000 | ||
Other-Than-Temporary Impairments | 1,000,000 | ' | 1,000,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 43,000,000 | ' | 37,000,000 | ||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 42,727,000 | ' | 36,782,000 | ||
Gross Unrealized Gains | 3,223,000 | ' | 2,450,000 | ||
Other-Than-Temporary Impairments | 1,097,000 | ' | 1,123,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 42,727,000 | ' | 36,782,000 | ||
State and Local Jurisdiction [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 281,000,000 | ' | 255,000,000 | ||
Gross Unrealized Gains | 1,000,000 | ' | 1,000,000 | ||
Other-Than-Temporary Impairments | 0 | ' | 0 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 281,000,000 | ' | 255,000,000 | ||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 280,612,000 | ' | 254,638,000 | ||
Gross Unrealized Gains | 972,000 | ' | 748,000 | ||
Other-Than-Temporary Impairments | 345,000 | ' | 370,000 | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 280,612,000 | ' | 254,638,000 | ||
Within One Year [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 82,000,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 82,000,000 | ' | ' | ||
Within One Year [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 82,190,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 82,190,000 | ' | ' | ||
One Year To Five Year [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 386,000,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 386,000,000 | ' | ' | ||
One Year To Five Year [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 386,173,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 386,173,000 | ' | ' | ||
Five Year To Ten Year [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 193,000,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 193,000,000 | ' | ' | ||
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 193,018,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 193,018,000 | ' | ' | ||
After Ten Year [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 269,000,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | 269,000,000 | ' | ' | ||
After Ten Year [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | ||
Nuclear Trust Fund Investments [Abstract] | ' | ' | ' | ||
Estimated Fair Value | 268,186,000 | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | ' | ' | ' | ||
Contractual Maturities, Fair Value of Debt Securities | $268,186,000 | ' | ' | ||
[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 | 12 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | ||||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | $292,000,000 | [1] | ' | $118,000,000 | [1] | |
Other Temporary Investments | 310,000,000 | ' | 353,000,000 | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 391,000,000 | ' | 457,000,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,962,000,000 | ' | 1,932,000,000 | |||
Total Assets | 2,955,000,000 | ' | 2,860,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 197,000,000 | ' | 267,000,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 117,000,000 | 86,000,000 | 86,000,000 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 84,000,000 | [2],[3] | -4,000,000 | [2],[3] | ' | |
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | -10,000,000 | [2] | -5,000,000 | [2] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 9,000,000 | 1,000,000 | ' | |||
Purchases, Issuances and Settlements | -100,000,000 | [4] | -6,000,000 | [4] | ' | |
Transfers into Level 3 | -4,000,000 | [5],[6] | 6,000,000 | [5],[6] | ' | |
Transfers out of Level 3 | -2,000,000 | [6],[7] | 0 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 11,000,000 | [8] | -2,000,000 | [8] | ' | |
Ending Balance | 105,000,000 | 76,000,000 | 117,000,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Significant Unobservable Input Counterparty Credit Risk | 3.15% | [9] | ' | 3.16% | [9] | |
Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 16,000,000 | [1] | ' | 16,000,000 | [1] | |
Other Temporary Investments | 291,000,000 | ' | 334,000,000 | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 20,000,000 | ' | 22,000,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,023,000,000 | ' | 1,020,000,000 | |||
Total Assets | 1,350,000,000 | ' | 1,392,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 30,000,000 | ' | 30,000,000 | |||
Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 1,000,000 | [1] | ' | 1,000,000 | [1] | |
Other Temporary Investments | 7,000,000 | ' | 8,000,000 | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 609,000,000 | ' | 565,000,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 930,000,000 | ' | 901,000,000 | |||
Total Assets | 1,547,000,000 | ' | 1,475,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 512,000,000 | ' | 499,000,000 | |||
Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Other Temporary Investments | 0 | ' | 0 | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 130,000,000 | ' | 142,000,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Total Assets | 130,000,000 | ' | 142,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 25,000,000 | ' | 25,000,000 | |||
Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 275,000,000 | [1] | ' | 101,000,000 | [1] | |
Other Temporary Investments | 12,000,000 | ' | 11,000,000 | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -368,000,000 | ' | -272,000,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 9,000,000 | ' | 11,000,000 | |||
Total Assets | -72,000,000 | ' | -149,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -370,000,000 | ' | -287,000,000 | |||
2014 [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 | 2,000,000 | ' | 4,000,000 | |||
2014 [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 | 32,000,000 | ' | 25,000,000 | |||
2014 [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 | 15,000,000 | ' | 27,000,000 | |||
2015 - 2017 [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 | -11,000,000 | ' | -11,000,000 | |||
2015 - 2017 [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 | 56,000,000 | ' | 37,000,000 | |||
2015 - 2017 [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 | 49,000,000 | ' | 60,000,000 | |||
2018 - 2019 [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 | |||
2018 - 2019 [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 | ' | 7,000,000 | |||
2018 - 2019 [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 | 16,000,000 | ' | 14,000,000 | |||
2020 - 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 | 5,000,000 | ' | 5,000,000 | |||
2020 - 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 | 23,000,000 | ' | 19,000,000 | |||
Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 370,000,000 | [10],[11] | ' | 440,000,000 | [10],[12] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 178,000,000 | [10],[11] | ' | 245,000,000 | [10],[12] | |
Risk Management Commodity Contracts [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 20,000,000 | [10],[11] | ' | 22,000,000 | [10],[12] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 30,000,000 | [10],[11] | ' | 30,000,000 | [10],[12] | |
Risk Management Commodity Contracts [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 586,000,000 | [10],[11] | ' | 549,000,000 | [10],[12] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 485,000,000 | [10],[11] | ' | 475,000,000 | [10],[12] | |
Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 128,000,000 | [10],[11] | ' | 142,000,000 | [10],[12] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 25,000,000 | [10],[11] | ' | 22,000,000 | [10],[12] | |
Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -364,000,000 | [10],[11] | ' | -273,000,000 | [10],[12] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -362,000,000 | [10],[11] | ' | -282,000,000 | [10],[12] | |
Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 116,000,000 | ' | 132,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 23,000,000 | ' | 22,000,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 1.45 | [13] | ' | 11.42 | [13] | |
Forward Price Range High | 131.46 | [13] | ' | 120.72 | [13] | |
FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 14,000,000 | ' | 10,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,000,000 | ' | 3,000,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | [13] | ' | -5.1 | [13] | |
Forward Price Range High | 9.17 | [13] | ' | 10.44 | [13] | |
Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 13,000,000 | [10] | ' | 7,000,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 5,000,000 | [10] | ' | 6,000,000 | [10] | |
Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 0 | [10] | |
Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 21,000,000 | [10] | ' | 15,000,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 15,000,000 | [10] | ' | 11,000,000 | [10] | |
Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 2,000,000 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 3,000,000 | [10] | |
Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -10,000,000 | [10] | ' | -8,000,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -10,000,000 | [10] | ' | -8,000,000 | [10] | |
Interest Rate Foreign Currency Hedges [Member] | ' | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,000,000 | ' | 2,000,000 | |||
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,000,000 | ' | 2,000,000 | |||
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Interest Rate Foreign Currency Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Fair Value Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 4,000,000 | ' | 4,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 12,000,000 | ' | 14,000,000 | |||
Fair Value Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | ' | 0 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Fair Value Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 2,000,000 | ' | 1,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 10,000,000 | ' | 11,000,000 | |||
Fair Value Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | ' | 0 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Fair Value Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 2,000,000 | ' | 3,000,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,000,000 | ' | 3,000,000 | |||
Appalachian Power Co [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 13,572,000 | [1] | ' | 2,750,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 29,985,000 | ' | 38,119,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 43,557,000 | ' | 40,869,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 12,565,000 | ' | 19,133,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 10,562,000 | 10,979,000 | 10,979,000 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 29,162,000 | [2],[3] | -1,456,000 | [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] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | ' | |||
Purchases, Issuances and Settlements | -31,781,000 | [4] | 257,000 | [4] | ' | |
Transfers into Level 3 | -3,825,000 | [5],[6] | 632,000 | [5],[6] | ' | |
Transfers out of Level 3 | -6,000 | [6],[7] | -533,000 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 3,289,000 | [8] | -1,123,000 | [8] | ' | |
Ending Balance | 7,401,000 | 8,756,000 | ' | |||
Appalachian Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 13,536,000 | [1] | ' | 2,714,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 393,000 | ' | 827,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 13,929,000 | ' | 3,541,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 306,000 | ' | 700,000 | |||
Appalachian Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 38,078,000 | ' | 54,837,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 38,078,000 | ' | 54,837,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 29,476,000 | ' | 49,533,000 | |||
Appalachian Power Co [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 10,508,000 | ' | 12,097,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 10,508,000 | ' | 12,097,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 3,107,000 | ' | 1,535,000 | |||
Appalachian Power Co [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 36,000 | [1] | ' | 36,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -18,994,000 | ' | -29,642,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | -18,958,000 | ' | -29,606,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -20,324,000 | ' | -32,635,000 | |||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 29,776,000 | [10],[14] | ' | 37,756,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 12,490,000 | [10],[14] | ' | 18,846,000 | [10],[14] | |
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 393,000 | [10],[14] | ' | 827,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 306,000 | [10],[14] | ' | 700,000 | [10],[14] | |
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 37,854,000 | [10],[14] | ' | 54,448,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 29,386,000 | [10],[14] | ' | 49,220,000 | [10],[14] | |
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 10,508,000 | [10],[14] | ' | 12,097,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 3,107,000 | [10],[14] | ' | 1,535,000 | [10],[14] | |
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -18,979,000 | [10],[14] | ' | -29,616,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -20,309,000 | [10],[14] | ' | -32,609,000 | [10],[14] | |
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 6,454,000 | ' | 9,359,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,822,000 | ' | 960,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 13.34 | ' | 13.04 | |||
Forward Price Range High | 59.6 | ' | 80.5 | |||
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 4,054,000 | ' | 2,738,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 285,000 | ' | 575,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | ' | -5.1 | |||
Forward Price Range High | 9.17 | ' | 10.44 | |||
Appalachian Power Co [Member] | Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 209,000 | [10] | ' | 363,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 75,000 | [10] | ' | 287,000 | [10] | |
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 0 | [10] | |
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 224,000 | [10] | ' | 389,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 90,000 | [10] | ' | 313,000 | [10] | |
Appalachian Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 0 | [10] | |
Appalachian Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -15,000 | [10] | ' | -26,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -15,000 | [10] | ' | -26,000 | [10] | |
Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 22,063,000 | ' | 26,883,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,962,151,000 | ' | 1,931,610,000 | |||
Total Assets | 1,984,214,000 | ' | 1,958,493,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 9,512,000 | ' | 13,975,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 7,164,000 | 7,541,000 | 7,541,000 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 18,219,000 | [2],[3] | -1,005,000 | [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] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | ' | |||
Purchases, Issuances and Settlements | -19,995,000 | [4] | 179,000 | [4] | ' | |
Transfers into Level 3 | -2,594,000 | [5],[6] | 434,000 | [5],[6] | ' | |
Transfers out of Level 3 | -4,000 | [6],[7] | -366,000 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 2,052,000 | [8] | -732,000 | [8] | ' | |
Ending Balance | 4,842,000 | 6,051,000 | ' | |||
Indiana Michigan Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 267,000 | ' | 561,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,023,721,000 | ' | 1,020,593,000 | |||
Total Assets | 1,023,988,000 | ' | 1,021,154,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 208,000 | ' | 475,000 | |||
Indiana Michigan Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 28,898,000 | ' | 38,901,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 929,567,000 | ' | 900,295,000 | |||
Total Assets | 958,465,000 | ' | 939,196,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 22,150,000 | ' | 35,273,000 | |||
Indiana Michigan Power Co [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 6,945,000 | ' | 8,205,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Total Assets | 6,945,000 | ' | 8,205,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,104,000 | ' | 1,041,000 | |||
Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -14,047,000 | ' | -20,784,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 8,863,000 | ' | 10,722,000 | |||
Total Assets | -5,184,000 | ' | -10,062,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -14,950,000 | ' | -22,814,000 | |||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 21,921,000 | [10],[14] | ' | 26,667,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 9,461,000 | [10],[14] | ' | 13,781,000 | [10],[14] | |
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 267,000 | [10],[14] | ' | 561,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 208,000 | [10],[14] | ' | 475,000 | [10],[14] | |
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 28,746,000 | [10],[14] | ' | 38,667,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 22,089,000 | [10],[14] | ' | 35,061,000 | [10],[14] | |
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 6,945,000 | [10],[14] | ' | 8,205,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 2,104,000 | [10],[14] | ' | 1,041,000 | [10],[14] | |
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -14,037,000 | [10],[14] | ' | -20,766,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -14,940,000 | [10],[14] | ' | -22,796,000 | [10],[14] | |
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 4,378,000 | ' | 6,348,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 1,914,000 | ' | 651,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 13.34 | ' | 13.04 | |||
Forward Price Range High | 59.6 | ' | 80.5 | |||
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 2,567,000 | ' | 1,857,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 190,000 | ' | 390,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | ' | -5.1 | |||
Forward Price Range High | 9.17 | ' | 10.44 | |||
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 142,000 | [10] | ' | 216,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 51,000 | [10] | ' | 194,000 | [10] | |
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 0 | [10] | |
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 152,000 | [10] | ' | 234,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 61,000 | [10] | ' | 212,000 | [10] | |
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10] | ' | 0 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10] | ' | 0 | [10] | |
Indiana Michigan Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -10,000 | [10] | ' | -18,000 | [10] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -10,000 | [10] | ' | -18,000 | [10] | |
Ohio Power Co [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 32,066,000 | [1] | ' | 19,399,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 3,082,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 36,046,000 | ' | 22,481,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 2,920,000 | 15,429,000 | 15,429,000 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 30,963,000 | [2],[3] | -2,055,000 | [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] | -1,988,000 | [2] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | ' | |||
Purchases, Issuances and Settlements | -34,036,000 | [4] | 366,000 | [4] | ' | |
Transfers into Level 3 | 0 | [5],[6] | 888,000 | [5],[6] | ' | |
Transfers out of Level 3 | 0 | [6],[7] | -749,000 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 4,065,000 | [8] | 490,000 | [8] | ' | |
Ending Balance | 3,912,000 | 12,381,000 | ' | |||
Ohio Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 32,054,000 | [1] | ' | 19,387,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 32,054,000 | ' | 19,387,000 | |||
Ohio Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 162,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 76,000 | ' | 162,000 | |||
Ohio Power Co [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 3,269,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 3,990,000 | ' | 3,269,000 | |||
Ohio Power Co [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 12,000 | [1] | ' | 12,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | -349,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | -74,000 | ' | -337,000 | |||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 3,980,000 | [10],[14] | ' | 2,920,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10],[14] | ' | 0 | [10],[14] | |
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [10],[14] | ' | 0 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10],[14] | ' | 0 | [10],[14] | |
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 76,000 | [10],[14] | ' | 0 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 5,000 | [10],[14] | ' | 0 | [10],[14] | |
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 3,990,000 | [10],[14] | ' | 3,269,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 78,000 | [10],[14] | ' | 349,000 | [10],[14] | |
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | -86,000 | [10],[14] | ' | -349,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -83,000 | [10],[14] | ' | -349,000 | [10],[14] | |
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | ' | 0 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | 0 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 0 | ' | 0 | |||
Forward Price Range High | 0 | ' | 0 | |||
Ohio Power Co [Member] | FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 3,990,000 | ' | 3,269,000 | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 78,000 | ' | 349,000 | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | ' | -5.1 | |||
Forward Price Range High | 9.17 | ' | 10.44 | |||
Ohio Power Co [Member] | Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 162,000 | [10] | ||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 162,000 | [10] | ||
Ohio Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Ohio Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Public Service Co Of Oklahoma [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 1,167,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 0 | 0 | 0 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 0 | [2],[3] | 0 | [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] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | ' | |||
Purchases, Issuances and Settlements | 0 | [4] | 0 | [4] | ' | |
Transfers into Level 3 | 0 | [5],[6] | 0 | [5],[6] | ' | |
Transfers out of Level 3 | 0 | [6],[7] | 0 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 349,000 | [8] | 0 | [8] | ' | |
Ending Balance | 349,000 | 0 | ' | |||
Public Service Co Of Oklahoma [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | |||
Public Service Co Of Oklahoma [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 1,162,000 | |||
Public Service Co Of Oklahoma [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | |||
Public Service Co Of Oklahoma [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 5,000 | |||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 1,349,000 | [10],[14] | ' | 1,083,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 83,000 | [10],[14] | ' | 85,000 | [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] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 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 | 922,000 | [10],[14] | ' | 1,078,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 4,000 | [10],[14] | ' | 81,000 | [10],[14] | |
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 481,000 | [10],[14] | ' | 0 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 132,000 | [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 | -54,000 | [10],[14] | ' | 5,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -53,000 | [10],[14] | ' | 4,000 | [10],[14] | |
Public Service Co Of Oklahoma [Member] | Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | ' | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 0 | ' | ' | |||
Forward Price Range High | 0 | ' | ' | |||
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 481,000 | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 132,000 | ' | ' | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | ' | ' | |||
Forward Price Range High | 9.17 | ' | ' | |||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 84,000 | [10] | ||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 84,000 | [10] | ||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Public Service Co Of Oklahoma [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Southwestern Electric Power Co [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 17,995,000 | [1] | ' | 17,241,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 1,179,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 19,902,000 | ' | 18,420,000 | |||
Changes in the Fair Value of Net Trading Derivatives and other investments | ' | ' | ' | |||
Beginning Balance | 0 | 0 | 0 | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | 0 | [2],[3] | 0 | [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] | ' | |
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | ' | |||
Purchases, Issuances and Settlements | 0 | [4] | 0 | [4] | ' | |
Transfers into Level 3 | 0 | [5],[6] | 0 | [5],[6] | ' | |
Transfers out of Level 3 | 0 | [6],[7] | 0 | [6],[7] | ' | |
Changes in Fair Value Allocated to Regulated Jurisdictions | 442,000 | [8] | 0 | [8] | ' | |
Ending Balance | 442,000 | 0 | ' | |||
Southwestern Electric Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 15,537,000 | [1] | ' | 15,871,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 15,537,000 | ' | 15,871,000 | |||
Southwestern Electric Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 1,330,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 1,471,000 | ' | 1,330,000 | |||
Southwestern Electric Power Co [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 0 | [1] | ' | 0 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 609,000 | ' | 0 | |||
Southwestern Electric Power Co [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Cash and Cash Equivalents | 2,458,000 | [1] | ' | 1,370,000 | [1] | |
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | -151,000 | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Total Assets | 2,285,000 | ' | 1,219,000 | |||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 1,907,000 | [10],[14] | ' | 1,082,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | [10],[14] | ' | 0 | [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] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 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 | 1,471,000 | [10],[14] | ' | 1,233,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 4,000 | [10],[14] | ' | 154,000 | [10],[14] | |
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 609,000 | [10],[14] | ' | 0 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 167,000 | [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 | -173,000 | [10],[14] | ' | -151,000 | [10],[14] | |
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | -171,000 | [10],[14] | ' | -154,000 | [10],[14] | |
Southwestern Electric Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 0 | ' | ' | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | 0 | ' | ' | |||
Forward Price Range High | 0 | ' | ' | |||
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 609,000 | ' | ' | |||
Liabilities: | ' | ' | ' | |||
Risk Management Liabilities | 167,000 | ' | ' | |||
Level 3 Quantitative Information [Abstract] | ' | ' | ' | |||
Forward Price Range Low | -5.05 | ' | ' | |||
Forward Price Range High | 9.17 | ' | ' | |||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 97,000 | [10] | ||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 97,000 | [10] | ||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Southwestern Electric Power Co [Member] | Commodity Hedges [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | ' | ' | 0 | [10] | ||
Cash [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 206,000,000 | [1] | ' | 250,000,000 | [1] | |
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 12,000,000 | [15] | ' | 19,000,000 | [15] | |
Cash [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 187,000,000 | [1] | ' | 231,000,000 | [1] | |
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 3,000,000 | [15] | ' | 8,000,000 | [15] | |
Cash [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 7,000,000 | [1] | ' | 8,000,000 | [1] | |
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [15] | ' | 0 | [15] | |
Cash [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | [1] | ' | 0 | [1] | |
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [15] | ' | 0 | [15] | |
Cash [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 12,000,000 | [1] | ' | 11,000,000 | [1] | |
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 9,000,000 | [15] | ' | 11,000,000 | [15] | |
Cash [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 12,439,000 | [16] | ' | 18,804,000 | [16] | |
Cash [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 3,576,000 | [16] | ' | 8,082,000 | [16] | |
Cash [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [16] | ' | 0 | [16] | |
Cash [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [16] | ' | 0 | [16] | |
Cash [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 8,863,000 | [16] | ' | 10,722,000 | [16] | |
Fixed Income Funds [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 930,000,000 | ' | 901,000,000 | |||
Fixed Income Funds [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Fixed Income Funds [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 930,000,000 | ' | 901,000,000 | |||
Fixed Income Funds [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 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 | |||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 929,567,000 | ' | 900,295,000 | |||
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 | |||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 929,567,000 | ' | 900,295,000 | |||
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 | |||
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 | |||
Mutual Funds Fixed Income [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 80,000,000 | ' | 80,000,000 | |||
Mutual Funds Fixed Income [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 80,000,000 | ' | 80,000,000 | |||
Mutual Funds Fixed Income [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | ' | 0 | |||
Mutual Funds Fixed Income [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | ' | 0 | |||
Mutual Funds Fixed Income [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | ' | 0 | |||
Domestic [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,020,000,000 | [17] | ' | 1,012,000,000 | [17] | |
Domestic [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,020,000,000 | [17] | ' | 1,012,000,000 | [17] | |
Domestic [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [17] | ' | 0 | [17] | |
Domestic [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [17] | ' | 0 | [17] | |
Domestic [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | [17] | ' | 0 | [17] | |
Domestic [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,020,145,000 | [17] | ' | 1,012,511,000 | [17] | |
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 1,020,145,000 | [17] | ' | 1,012,511,000 | [17] | |
Domestic [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] | |
Domestic [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] | |
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 | [17] | ' | 0 | [17] | |
Mutual Funds Equity [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 24,000,000 | [17] | ' | 23,000,000 | [17] | |
Mutual Funds Equity [Member] | Level 1 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 24,000,000 | [17] | ' | 23,000,000 | [17] | |
Mutual Funds Equity [Member] | Level 2 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | [17] | ' | 0 | [17] | |
Mutual Funds Equity [Member] | Level 3 [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | [17] | ' | 0 | [17] | |
Mutual Funds Equity [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Assets: | ' | ' | ' | |||
Other Temporary Investments | 0 | [17] | ' | 0 | [17] | |
Cash and Cash Equivalents [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 12,000,000 | ' | 19,000,000 | |||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 12,439,000 | ' | 18,804,000 | |||
US Government Agencies Debt Securities [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 606,000,000 | ' | 609,000,000 | |||
US Government Agencies Debt Securities [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
US Government Agencies Debt Securities [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 606,000,000 | ' | 609,000,000 | |||
US Government Agencies Debt Securities [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
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 | |||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 606,228,000 | ' | 608,875,000 | |||
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 | |||
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 | 606,228,000 | ' | 608,875,000 | |||
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 | |||
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 | |||
Corporate Debt [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 43,000,000 | ' | 37,000,000 | |||
Corporate Debt [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Corporate Debt [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 43,000,000 | ' | 37,000,000 | |||
Corporate Debt [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Corporate Debt [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 42,727,000 | ' | 36,782,000 | |||
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 | |||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 42,727,000 | ' | 36,782,000 | |||
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 | |||
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 | |||
State and Local Jurisdiction [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 281,000,000 | ' | 255,000,000 | |||
State and Local Jurisdiction [Member] | Level 1 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | ' | 0 | |||
State and Local Jurisdiction [Member] | Level 2 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 281,000,000 | ' | 255,000,000 | |||
State and Local Jurisdiction [Member] | Level 3 [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 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 | |||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | ' | ' | ' | |||
Spent Nuclear Fuel and Decommissioning Trusts | 280,612,000 | ' | 254,638,000 | |||
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 | |||
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 | 280,612,000 | ' | 254,638,000 | |||
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 | |||
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 | |||
Dedesignated Risk Management Contracts [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 4,000,000 | [18] | ' | 6,000,000 | [18] | |
Dedesignated Risk Management Contracts [Member] | Level 1 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [18] | ' | 0 | [18] | |
Dedesignated Risk Management Contracts [Member] | Level 2 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [18] | ' | 0 | [18] | |
Dedesignated Risk Management Contracts [Member] | Level 3 [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | 0 | [18] | ' | 0 | [18] | |
Dedesignated Risk Management Contracts [Member] | Fair Value Inputs Other [Member] | ' | ' | ' | |||
Risk Management Assets | ' | ' | ' | |||
Risk Management Assets | $4,000,000 | [18] | ' | $6,000,000 | [18] | |
[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 March 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $2 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts. | |||||
[12] | The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. 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 ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||
[16] | Amounts in bOtherb column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. | |||||
[17] | Amounts represent publicly traded equity securities and equity-based mutual funds. | |||||
[18] | 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 | |
Mar. 31, 2014 | Mar. 31, 2013 | |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | ($307,000,000) | ($195,000,000) |
Interest and Investment Income | 1,000,000 | 3,000,000 |
Net Income (Loss) | 561,000,000 | 364,000,000 |
Appalachian Power Co [Member] | ' | ' |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | -66,248,000 | -47,012,000 |
Net Income (Loss) | 101,851,000 | 70,548,000 |
Indiana Michigan Power Co [Member] | ' | ' |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | -38,315,000 | -21,263,000 |
Net Income (Loss) | 87,089,000 | 43,457,000 |
Ohio Power Co [Member] | ' | ' |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | -34,052,000 | -69,796,000 |
Net Income (Loss) | 60,774,000 | 129,774,000 |
Public Service Co Of Oklahoma [Member] | ' | ' |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | -4,989,000 | -8,634,000 |
Net Income (Loss) | 8,448,000 | 13,693,000 |
Southwestern Electric Power Co [Member] | ' | ' |
Income Taxes (Textuals) [Abstract] | ' | ' |
Income Tax Benefit | -12,165,000 | -6,796,000 |
Net Income (Loss) | $22,962,000 | $11,548,000 |
Financing_Activities_Details
Financing Activities (Details) (USD $) | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 1 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | 3 Months Ended | |||||||||||||||||||||||||||||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Apr. 25, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | Mar. 31, 2014 | Mar. 31, 2014 | |||
AEP Subsidiaries [Member] | AEP Subsidiaries [Member] | AEP Subsidiaries [Member] | AEP Generating Co [Member] | AEP Texas Central Co [Member] | AEP Texas Central 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] | 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] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Southwestern Electric Power Co [Member] | Transource Missouri [Member] | ||||||
Notes Payable One [Member] | Senior Unsecured Notes One [Member] | Securitization Bonds One [Member] | Securitization Bonds Two [Member] | Land Note [Member] | Notes Payable One [Member] | Notes Payable One [Member] | Notes Payable Two [Member] | Notes Payable Three [Member] | Notes Payable Four [Member] | Long-term Debt [Member] | Long Term Debt Two [Member] | Senior Unsecured Notes One [Member] | Long-term Debt [Member] | Long-term Debt [Member] | Long Term Debt Two [Member] | Notes Payable Two [Member] | Long-term Debt [Member] | |||||||||||||||||||||||
Subsequent Event [Member] | ||||||||||||||||||||||||||||||||||||||||
Long-term Debt | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Senior Unsecured Notes | $11,571,000,000 | ' | $11,799,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Pollution Control Bonds | 1,932,000,000 | ' | 1,932,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Notes Payable | 342,000,000 | ' | 369,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Securitization Bonds | 2,574,000,000 | ' | 2,686,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Spent Nuclear Fuel Obligation | 265,000,000 | [1] | ' | 265,000,000 | [1] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Other Long-term Debt | 1,434,000,000 | ' | 1,360,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Fair Value of Interest Rate Hedges | -7,000,000 | ' | -9,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unamortized Discount, Net | -24,000,000 | ' | -25,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total Long-term Debt Outstanding | 18,087,000,000 | ' | 18,377,000,000 | ' | ' | ' | ' | ' | ' | 4,194,516,000 | ' | 4,194,357,000 | ' | 2,012,844,000 | ' | 2,039,016,000 | ' | ' | ' | ' | ' | ' | ' | 2,510,285,000 | ' | 2,735,175,000 | ' | ' | 1,049,793,000 | ' | 999,810,000 | ' | ' | 2,041,796,000 | ' | 2,043,332,000 | ' | ' | ||
Long-term Debt Due Within One Year | 1,612,000,000 | ' | 1,549,000,000 | 449,000,000 | 416,000,000 | ' | ' | ' | ' | 553,399,000 | ' | 342,360,000 | ' | 287,598,000 | ' | 294,845,000 | ' | ' | ' | ' | ' | ' | ' | 235,785,000 | ' | 438,595,000 | ' | ' | 34,118,000 | ' | 34,115,000 | ' | ' | 56,750,000 | ' | 3,250,000 | ' | ' | ||
Long-term Debt | 16,475,000,000 | ' | 16,828,000,000 | 2,388,000,000 | 2,532,000,000 | ' | ' | ' | ' | 3,555,117,000 | ' | 3,765,997,000 | ' | 1,725,246,000 | ' | 1,744,171,000 | ' | ' | ' | ' | ' | ' | ' | 2,274,500,000 | ' | 2,296,580,000 | ' | ' | 1,015,675,000 | ' | 965,695,000 | ' | ' | 1,985,046,000 | ' | 2,040,082,000 | ' | ' | ||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Issuances | 77,000,000 | [2] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 50,000,000 | ' | ' | ' | ' | ' | 27,000,000 | |
Retirements and Principal Payments | 370,000,000 | 858,000,000 | ' | ' | ' | 1,000,000 | 4,000,000 | 72,000,000 | 40,000,000 | 8,000 | 7,000 | ' | 8,000 | 26,337,000 | 24,864,000 | ' | 9,866,000 | 13,000,000 | 5,324,000 | 5,214,000 | 3,611,000 | 2,063,000 | 259,000 | 225,029,000 | 500,000,000 | ' | 225,000,000 | 29,000 | 102,000 | 99,000 | ' | ' | 102,000 | 1,625,000 | 1,625,000 | ' | 1,625,000 | ' | ||
Interest Rate (Percentage) | ' | ' | ' | ' | ' | ' | 6.33% | 5.09% | 6.25% | ' | ' | ' | 13.72% | ' | ' | ' | ' | ' | ' | ' | 2.12% | ' | 6.00% | ' | ' | ' | 4.85% | 1.15% | ' | ' | ' | ' | 3.00% | ' | ' | ' | 4.58% | ' | ||
Interest Rate (Variable) | ' | ' | ' | ' | ' | 'Variable | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'Variable | ' | 'Variable | 'Variable | ' | 'Variable | ' | ' | ' | ' | ' | ' | ' | ' | ' | 'Variable | ' | ' | ' | ' | ' | 'Variable | ||
Due Date | ' | ' | ' | ' | ' | '2017 | '2037 | '2015 | '2016 | ' | ' | ' | '2026 | ' | ' | ' | '2017 | ' | '2016 | '2016 | '2016 | '2015 | '2025 | ' | ' | ' | '2014 | '2028 | ' | ' | ' | '2016 | '2027 | ' | ' | ' | '2032 | '2018 | ||
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Maximum Borrowings from Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 55,640,000 | ' | ' | ' | ' | 121,100,000 | ' | ' | ' | ' | 130,258,000 | ' | ' | ' | ' | ||
Maximum Loans to Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | 249,630,000 | ' | ' | ' | 158,857,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 405,350,000 | ' | ' | ' | ' | 0 | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ||
Average Borrowings from Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0 | ' | ' | ' | 0 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 25,930,000 | ' | ' | ' | ' | 58,500,000 | ' | ' | ' | ' | 61,132,000 | ' | ' | ' | ' | ||
Average Loans to Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | 164,681,000 | ' | ' | ' | 92,303,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 135,747,000 | ' | ' | ' | ' | 0 | ' | ' | ' | ' | 0 | ' | ' | ' | ' | ||
Net Loans (Borrowings) to/from Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | 245,516,000 | ' | ' | ' | 59,162,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | -27,108,000 | ' | ' | ' | ' | -70,119,000 | ' | ' | ' | ' | -117,342,000 | ' | ' | ' | ' | ||
Authorized Short-term Borrowing Limit | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 600,000,000 | ' | ' | ' | ' | 300,000,000 | ' | ' | ' | ' | 350,000,000 | ' | ' | ' | ' | ||
Maximum and Minimum Interest Rates | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Maximum Interest Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.33% | 0.43% | ' | ' | 0.33% | 0.43% | ' | ' | ' | ' | ' | ' | ' | ' | 0.33% | 0.43% | ' | ' | ' | 0.33% | 0.43% | ' | ' | ' | 0.33% | 0.43% | ' | ' | ' | ||
Minimum Interest Rate | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.28% | 0.35% | ' | ' | 0.28% | 0.35% | ' | ' | ' | ' | ' | ' | ' | ' | 0.28% | 0.35% | ' | ' | ' | 0.28% | 0.35% | ' | ' | ' | 0.28% | 0.35% | ' | ' | ' | ||
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Average Interest Rate for Funds Borrowed | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.00% | 0.38% | ' | ' | 0.00% | 0.36% | ' | ' | ' | ' | ' | ' | ' | ' | 0.31% | 0.36% | ' | ' | ' | 0.31% | 0.36% | ' | ' | ' | 0.31% | 0.00% | ' | ' | ' | ||
Average Interest Rate for Funds Loaned | ' | ' | ' | ' | ' | ' | ' | ' | ' | 0.31% | 0.37% | ' | ' | 0.31% | 0.37% | ' | ' | ' | ' | ' | ' | ' | ' | 0.29% | 0.37% | ' | ' | ' | 0.00% | 0.38% | ' | ' | ' | 0.00% | 0.38% | ' | ' | ' | ||
Short-term Debt: | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Securitized Debt for Receivables | 700,000,000 | [3] | ' | 700,000,000 | [3] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commercial Paper | 632,000,000 | ' | 57,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total Short-term Debt | 1,332,000,000 | ' | 757,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Securitized Debt for Receivables | 0.24% | [4] | ' | 0.23% | [4] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Commercial Paper | 0.31% | [4] | ' | 0.29% | [4] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' |
Comparative Accounts Receivable Information | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Effective Interest Rates on Securitization of Accounts Receivable | 0.24% | 0.23% | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Net Uncollectible Accounts Receivable Written Off | 8,000,000 | 7,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Customer Accounts Receivable Managed Portfolio | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | 997,000,000 | ' | 929,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total Principal Outstanding | 700,000,000 | ' | 700,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Delinquent Securitized Accounts Receivable | 55,000,000 | ' | 45,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable | 17,000,000 | ' | 16,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable | 278,000,000 | ' | 331,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Accounts Receivable and Accrued Unbilled Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Accounts Receivable and Accrued Unbilled Revenues | ' | ' | ' | ' | ' | ' | ' | ' | ' | 175,738,000 | ' | 156,599,000 | ' | 154,510,000 | ' | 139,257,000 | ' | ' | ' | ' | ' | ' | ' | 350,735,000 | ' | 324,287,000 | ' | ' | 111,522,000 | ' | 115,260,000 | ' | ' | 145,648,000 | ' | 149,337,000 | ' | ' | ||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ' | ' | ' | ' | ' | ' | ' | ' | ' | 2,423,000 | 1,556,000 | ' | ' | 2,040,000 | 1,452,000 | ' | ' | ' | ' | ' | ' | ' | ' | 7,498,000 | 4,669,000 | ' | ' | ' | 1,323,000 | 1,414,000 | ' | ' | ' | 1,566,000 | 1,380,000 | ' | ' | ' | ||
Proceeds from Sale of Receivables | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Proceeds from Sale of Receivables to AEP Credit | ' | ' | ' | ' | ' | ' | ' | ' | ' | 437,196,000 | 398,193,000 | ' | ' | 407,150,000 | 351,830,000 | ' | ' | ' | ' | ' | ' | ' | ' | 686,627,000 | 696,958,000 | ' | ' | ' | 290,217,000 | 240,275,000 | ' | ' | ' | 390,588,000 | 331,936,000 | ' | ' | ' | ||
Financing Activities (Textuals) [Abstract] | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Reacquired Pollution Controls Bonds Held by Trustees | 500,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | 40,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | 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 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Commitment from Bank Conduits that Expire in Two Years | 315,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Total Commitment from Bank Conduits to Finance Receivables | 700,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition | $309,000,000 | ' | $309,000,000 | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ' | ||
[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 $309 million as of March 31, 2014 and December 31, 2013, 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] | Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance. | |||||||||||||||||||||||||||||||||||||||
[4] | Weighted average rate. |
Variable_Interest_Entities_Det
Variable Interest Entities (Details) (USD $) | 3 Months Ended | ||||
Mar. 31, 2014 | Mar. 31, 2013 | Dec. 31, 2013 | |||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Minimum Percentage of Equity AEP Provides | 5.00% | ' | ' | ||
Securitization Bonds | $2,574,000,000 | ' | $2,686,000,000 | ||
Securitized Transition Assets | 2,308,000,000 | ' | 2,373,000,000 | ||
AEP Credit, Inc. [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
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 | 2,000,000,000 | ' | 2,000,000,000 | ||
Securitized Transition Assets | 1,800,000,000 | ' | 1,900,000,000 | ||
Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Insurance Premium Expense to Protected Cell | 16,000,000 | 15,000,000 | ' | ||
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 | 25,000,000 | ' | 25,000,000 | ||
Maximum Exposure | 25,000,000 | ' | 25,000,000 | ||
Transource Energy, LLC [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Equity and Voting Ownership Percentage | 86.50% | ' | ' | ||
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 | ||
Maximum Exposure | 19,000,000 | ' | 19,000,000 | ||
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 | 6,000,000 | ' | 6,000,000 | ||
Maximum Exposure | 6,000,000 | ' | 6,000,000 | ||
Current Assets [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 1,004,000,000 | ' | 935,000,000 | ||
Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 166,000,000 | ' | 232,000,000 | ||
Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 152,000,000 | ' | 143,000,000 | ||
Current Assets [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 4,000,000 | ' | ' | ||
Net Property Plant And Equipment [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 0 | ' | 0 | ||
Net Property Plant And Equipment [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 0 | ' | 0 | ||
Net Property Plant And Equipment [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 0 | ' | 0 | ||
Net Property Plant And Equipment [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 57,000,000 | ' | ' | ||
Other Non Current Assets [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 0 | ' | 1,000,000 | ||
Other Non Current Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 1,861,000,000 | [1] | ' | 1,918,000,000 | [2] |
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Intercompany Item Eliminated in Consolidation | 81,000,000 | ' | 82,000,000 | ||
Other Non Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 3,000,000 | ' | 3,000,000 | ||
Other Non Current Assets [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 5,000,000 | ' | ' | ||
Total Assets [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 1,004,000,000 | ' | 936,000,000 | ||
Total Assets [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 2,027,000,000 | ' | 2,150,000,000 | ||
Total Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 155,000,000 | ' | 146,000,000 | ||
Total Assets [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 66,000,000 | ' | ' | ||
Current Liabilities [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 894,000,000 | ' | 827,000,000 | ||
Current Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 304,000,000 | ' | 312,000,000 | ||
Current Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 48,000,000 | ' | 39,000,000 | ||
Current Liabilities [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 18,000,000 | ' | ' | ||
Noncurrent Liabilities [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 1,000,000 | ' | 1,000,000 | ||
Noncurrent Liabilities [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 1,705,000,000 | ' | 1,820,000,000 | ||
Noncurrent Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 67,000,000 | ' | 66,000,000 | ||
Noncurrent Liabilities [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 28,000,000 | ' | ' | ||
Equity [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 109,000,000 | ' | 108,000,000 | ||
Equity [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 18,000,000 | ' | 18,000,000 | ||
Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 40,000,000 | ' | 41,000,000 | ||
Equity [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 20,000,000 | ' | ' | ||
Total Liabilities And Equity [Member] | AEP Credit, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 1,004,000,000 | ' | 936,000,000 | ||
Total Liabilities And Equity [Member] | AEP Texas Central Transition Funding Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 2,027,000,000 | ' | 2,150,000,000 | ||
Total Liabilities And Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 155,000,000 | ' | 146,000,000 | ||
Total Liabilities And Equity [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 66,000,000 | ' | ' | ||
Appalachian Power Co [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Securitized Transition Assets | 364,984,000 | ' | 369,355,000 | ||
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 50,136,000 | 39,040,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 50,136,000 | 39,040,000 | ' | ||
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 | 19,304,000 | ' | 20,191,000 | ||
Maximum Exposure | 19,304,000 | ' | 20,191,000 | ||
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Securitization Bonds | 380,000,000 | ' | 380,000,000 | ||
Securitized Transition Assets | 365,000,000 | ' | 369,000,000 | ||
Appalachian Power Co [Member] | Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 15,981,000 | ' | 5,891,000 | ||
Appalachian Power Co [Member] | Net Property Plant And Equipment [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 0 | ' | 0 | ||
Appalachian Power Co [Member] | Other Non Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 373,521,000 | [3] | ' | 378,029,000 | [3] |
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Intercompany Item Eliminated in Consolidation | 4,000,000 | ' | 4,000,000 | ||
Appalachian Power Co [Member] | Total Assets [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 389,502,000 | ' | 383,920,000 | ||
Appalachian Power Co [Member] | Current Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 27,682,000 | ' | 14,000,000 | ||
Appalachian Power Co [Member] | Noncurrent Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 359,919,000 | ' | 368,018,000 | ||
Appalachian Power Co [Member] | Equity [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 1,901,000 | ' | 1,902,000 | ||
Appalachian Power Co [Member] | Total Liabilities And Equity [Member] | Appalachian Consumer Rate Relief Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 389,502,000 | ' | 383,920,000 | ||
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Payments Made by I&M to DCC Fuel | 25,000,000 | 26,000,000 | ' | ||
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 70,422,000 | 58,535,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 70,422,000 | 58,535,000 | ' | ||
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 31,969,000 | 27,498,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 31,969,000 | 27,498,000 | ' | ||
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 | 12,040,000 | ' | 12,864,000 | ||
Maximum Exposure | 12,040,000 | ' | 12,864,000 | ||
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 | 24,364,000 | ' | 23,916,000 | ||
Maximum Exposure | 24,364,000 | ' | 23,916,000 | ||
Indiana Michigan Power Co [Member] | Current Assets [Member] | DCC Fuel [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 109,374,000 | ' | 117,762,000 | ||
Indiana Michigan Power Co [Member] | Net Property Plant And Equipment [Member] | DCC Fuel [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 129,013,000 | ' | 156,820,000 | ||
Indiana Michigan Power Co [Member] | Other Non Current Assets [Member] | DCC Fuel [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 44,853,000 | ' | 60,450,000 | ||
Indiana Michigan Power Co [Member] | Total Assets [Member] | DCC Fuel [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 283,240,000 | ' | 335,032,000 | ||
Indiana Michigan Power Co [Member] | Current Liabilities [Member] | DCC Fuel [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 100,141,000 | ' | 107,815,000 | ||
Indiana Michigan Power Co [Member] | Noncurrent Liabilities [Member] | DCC Fuel [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 183,099,000 | ' | 227,217,000 | ||
Indiana Michigan Power Co [Member] | Total Liabilities And Equity [Member] | DCC Fuel [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 283,240,000 | ' | 335,032,000 | ||
Ohio Power Co [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Securitized Transition Assets | 126,597,000 | ' | 131,582,000 | ||
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 | 127,000,000 | ' | 132,000,000 | ||
Ohio Power Co [Member] | Billings from AEP Generating Co [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 0 | 38,711,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 0 | 38,711,000 | ' | ||
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 39,049,000 | 54,069,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 39,049,000 | 54,069,000 | ' | ||
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 | 14,046,000 | ' | 31,425,000 | ||
Maximum Exposure | 14,046,000 | ' | 31,425,000 | ||
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 | 0 | ' | 12,810,000 | ||
Maximum Exposure | 0 | ' | 12,810,000 | ||
Ohio Power Co [Member] | Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 35,958,000 | ' | 23,198,000 | ||
Ohio Power Co [Member] | Other Non Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 241,814,000 | [4] | ' | 251,409,000 | [4] |
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Intercompany Item Eliminated in Consolidation | 112,000,000 | ' | 116,000,000 | ||
Ohio Power Co [Member] | Total Assets [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 277,772,000 | ' | 274,607,000 | ||
Ohio Power Co [Member] | Current Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 59,590,000 | ' | 36,470,000 | ||
Ohio Power Co [Member] | Noncurrent Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 216,845,000 | ' | 236,800,000 | ||
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 | 277,772,000 | ' | 274,607,000 | ||
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 24,439,000 | 18,161,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 24,439,000 | 18,161,000 | ' | ||
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 | 9,330,000 | ' | 10,596,000 | ||
Maximum Exposure | 9,330,000 | ' | 10,596,000 | ||
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 39,000,000 | 44,000,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 39,000,000 | 44,000,000 | ' | ||
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 | 9,553,000 | ' | 9,243,000 | ||
Maximum Exposure | 94,743,000 | ' | 70,591,000 | ||
Billings from Affiliates | ' | ' | ' | ||
Billings from VIE | 2,000,000 | 18,000,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 2,000,000 | 18,000,000 | ' | ||
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 | 33,023,000 | 27,480,000 | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Billings from VIE | 33,023,000 | 27,480,000 | ' | ||
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 | 12,833,000 | ' | 13,520,000 | ||
Maximum Exposure | 12,833,000 | ' | 13,520,000 | ||
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 | ||
Maximum Exposure | 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 | 1,910,000 | ' | 1,600,000 | ||
Maximum Exposure | 1,910,000 | ' | 1,600,000 | ||
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 | ||
Maximum Exposure | 85,190,000 | ' | 61,348,000 | ||
Southwestern Electric Power Co [Member] | Current Assets [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 61,675,000 | ' | 66,478,000 | ||
Southwestern Electric Power Co [Member] | Net Property Plant And Equipment [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 153,928,000 | ' | 157,274,000 | ||
Southwestern Electric Power Co [Member] | Other Non Current Assets [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 50,140,000 | ' | 51,211,000 | ||
Southwestern Electric Power Co [Member] | Total Assets [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
ASSETS | ' | ' | ' | ||
Assets | 265,743,000 | ' | 274,963,000 | ||
Southwestern Electric Power Co [Member] | Current Liabilities [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 29,257,000 | ' | 32,812,000 | ||
Southwestern Electric Power Co [Member] | Noncurrent Liabilities [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 236,142,000 | ' | 241,673,000 | ||
Southwestern Electric Power Co [Member] | Equity [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | 344,000 | ' | 478,000 | ||
Southwestern Electric Power Co [Member] | Total Liabilities And Equity [Member] | Sabine Mining Co [Member] | ' | ' | ' | ||
LIABILITIES AND EQUITY | ' | ' | ' | ||
Liabilities and Equity | $265,743,000 | ' | $274,963,000 | ||
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% | ' | ' | ||
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% | ' | ' | ||
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Jointly Owned Utility Plant, Proportionate Ownership Share | 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% | ' | ' | ||
Great Plains Energy Inc [Member] | Transource Energy, LLC [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Equity and Voting Ownership Percentage | 13.50% | ' | ' | ||
First Energy Corp [Member] | Allegheny Series [Member] | ' | ' | ' | ||
Variable Interest Entities (Textuals) [Abstract] | ' | ' | ' | ||
Percentage of Ownership in Subsidiary | 100.00% | ' | ' | ||
[1] | Includes an intercompany item eliminated in consolidation of $81 million. | ||||
[2] | B B B B B B B B Includes an intercompany item eliminated in consolidation of $82 million. | ||||
[3] | Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively. | ||||
[4] | Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively. |