Document and Entity Information
Document and Entity Information - shares | 6 Months Ended | |
Jun. 30, 2017 | Jul. 27, 2017 | |
Entity Registrant Name | AMERICAN ELECTRIC POWER CO INC | |
Entity Central Index Key | 4,904 | |
Document Type | 10-Q | |
Document Period End Date | Jun. 30, 2017 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q2 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 491,840,382 | |
AEP Transmission Co [Member] | ||
Entity Registrant Name | AEP Transmission Company, LLC | |
Entity Central Index Key | 1,702,494 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 0 | |
Appalachian Power Co [Member] | ||
Entity Registrant Name | APPALACHIAN POWER CO | |
Entity Central Index Key | 6,879 | |
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 | 50,172 | |
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 | 73,986 | |
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 | 81,027 | |
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 | 92,487 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 7,536,640 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Revenues | ||||
Vertically Integrated Utilities | $ 2,095.7 | $ 2,108.2 | $ 4,365.5 | $ 4,326.3 |
Transmission and Distribution Utilities | 1,026.6 | 1,076.2 | 2,093 | 2,153.5 |
Generation & Marketing | 386.5 | 655.3 | 945.3 | 1,369.2 |
Other Revenues | 67.7 | 53.2 | 106 | 88.8 |
TOTAL REVENUES | 3,576.5 | 3,892.9 | 7,509.8 | 7,937.8 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 522.3 | 680.4 | 1,157.9 | 1,356 |
Purchased Electricity for Resale | 669.2 | 629.2 | 1,438.8 | 1,360.6 |
Other Operation | 604.2 | 664.5 | 1,206.4 | 1,379.6 |
Maintenance | 289 | 289.4 | 591.4 | 568.1 |
Asset Impairments and Other Related Charges | 1.9 | 0 | 13.1 | 0 |
Gain on Sale of Merchant Generation Assets | 0.1 | 0 | (226.4) | 0 |
Depreciation and Amortization | 485.5 | 513.8 | 967.4 | 1,010.9 |
Taxes Other Than Income Taxes | 259.6 | 249.4 | 519.4 | 503.5 |
TOTAL EXPENSES | 2,831.8 | 3,026.7 | 5,668 | 6,178.7 |
OPERATING INCOME (LOSS) | 744.7 | 866.2 | 1,841.8 | 1,759.1 |
Other Income (Expense): | ||||
Interest and Investment Income | 2.3 | 2.4 | 10.3 | 4.5 |
Carrying Costs Income | 5.7 | 6.3 | 11.6 | 10.2 |
Allowance for Equity Funds Used During Construction | 21 | 28.8 | 42.2 | 60.5 |
Interest Expense | (222.9) | (224.9) | (444.7) | (441.9) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 550.8 | 678.8 | 1,461.2 | 1,392.4 |
Income Tax Expense (Credit) | 190.6 | 165 | 533.8 | 400.5 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | 16 | (7.4) | 43 | 17.6 |
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 376.2 | 506.4 | 970.4 | 1,009.5 |
Income (Loss) from Discontinued Operations, Net of Tax | 0 | (2.5) | 0 | (2.5) |
Net Income (Loss) | 376.2 | 503.9 | 970.4 | 1,007 |
Net Income Attributable to Noncontrolling Interests | 1.2 | 1.8 | 3.2 | 3.7 |
Earnings Attributable to Common Shareholders | $ 375 | $ 502.1 | $ 967.2 | $ 1,003.3 |
Earnings Per Share | ||||
Weighted Average Number of Basic AEP Common Shares Outstanding | 491,790,752 | 491,459,541 | 491,751,614 | 491,283,967 |
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations | $ 0.76 | $ 1.03 | $ 1.97 | $ 2.05 |
Basic Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations | 0 | (0.01) | 0 | (0.01) |
Total Basic Earnings Per Share Attributable to AEP Common Shareholders | $ 0.76 | $ 1.02 | $ 1.97 | $ 2.04 |
Weighted Average Number of Diluted AEP Common Shares Outstanding | 492,642,100 | 491,641,400 | 492,337,255 | 491,486,853 |
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations | $ 0.76 | $ 1.03 | $ 1.96 | $ 2.05 |
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Discontinued Operations | 0 | (0.01) | 0 | (0.01) |
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders | 0.76 | 1.02 | 1.96 | 2.04 |
Common Stock, Dividends Per Share, Declared | $ 0.59 | $ 0.56 | $ 1.18 | $ 1.12 |
AEP Transmission Co [Member] | ||||
Revenues | ||||
Electrical Transmission Revenue | $ 44 | $ 34.1 | $ 63.3 | $ 56.1 |
Sales to AEP Affiliates | 185.4 | 119 | 318.8 | 176.6 |
TOTAL REVENUES | 229.4 | 153.1 | 382.1 | 232.7 |
Expenses | ||||
Other Operation | 11.3 | 6.3 | 20.4 | 13.5 |
Maintenance | 2.3 | 1.4 | 5.4 | 2.9 |
Depreciation and Amortization | 22.8 | 15.6 | 46.1 | 30.7 |
Taxes Other Than Income Taxes | 27.6 | 21.7 | 54.4 | 42.7 |
TOTAL EXPENSES | 64 | 45 | 126.3 | 89.8 |
OPERATING INCOME (LOSS) | 165.4 | 108.1 | 255.8 | 142.9 |
Other Income (Expense): | ||||
Interest Income | 0.1 | 0.1 | 0.3 | 0.1 |
Allowance for Equity Funds Used During Construction | 13.4 | 14.1 | 24.3 | 26.4 |
Interest Expense | (15.7) | (10.5) | (31.7) | (21.3) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 163.2 | 111.8 | 248.7 | 148.1 |
Income Tax Expense (Credit) | 55.8 | 37 | 84.3 | 47.5 |
Net Income (Loss) | 107.4 | 74.8 | 164.4 | 100.6 |
Appalachian Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 625.6 | 638.8 | 1,370.6 | 1,414.3 |
Sales to AEP Affiliates | 46.3 | 32.2 | 88.7 | 72.6 |
Other Revenues | 3.4 | 2.5 | 8.8 | 6.6 |
TOTAL REVENUES | 675.3 | 673.5 | 1,468.1 | 1,493.5 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 152.5 | 153.3 | 319.7 | 304 |
Purchased Electricity for Resale | 65.2 | 63.5 | 156 | 171.7 |
Other Operation | 137.9 | 111.2 | 250.5 | 231.8 |
Maintenance | 60.8 | 60.2 | 132 | 129.5 |
Depreciation and Amortization | 100.7 | 96.4 | 201.3 | 191.9 |
Taxes Other Than Income Taxes | 30.8 | 30.6 | 61 | 61.9 |
TOTAL EXPENSES | 547.9 | 515.2 | 1,120.5 | 1,090.8 |
OPERATING INCOME (LOSS) | 127.4 | 158.3 | 347.6 | 402.7 |
Other Income (Expense): | ||||
Interest Income | 0.5 | 0.2 | 0.8 | 0.5 |
Carrying Costs Income | 0.3 | 1 | 0.6 | 0.2 |
Allowance for Equity Funds Used During Construction | 2 | 2.3 | 3.5 | 4.6 |
Interest Expense | (48.2) | (47.3) | (96.3) | (94.3) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 82 | 114.5 | 256.2 | 313.7 |
Income Tax Expense (Credit) | 29.9 | 41.1 | 93.5 | 114 |
Net Income (Loss) | 52.1 | 73.4 | 162.7 | 199.7 |
Indiana Michigan Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 451.9 | 495.7 | 990.4 | 996.1 |
Other Revenues - Affiliated | 12.4 | 22.4 | 31.1 | 49.2 |
Other Revenues | 3 | 4.3 | 6.3 | 9.8 |
TOTAL REVENUES | 467.3 | 522.4 | 1,027.8 | 1,055.1 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 71.1 | 76.3 | 161.8 | 145.5 |
Purchased Electricity for Resale | 31 | 41 | 68.3 | 90.6 |
Purchased Electricity from AEP Affiliates | 49.9 | 56 | 103.8 | 101.4 |
Other Operation | 158.1 | 133.7 | 293.7 | 275 |
Maintenance | 50.7 | 48 | 102.1 | 88.9 |
Depreciation and Amortization | 49.8 | 47 | 99.8 | 94.1 |
Taxes Other Than Income Taxes | 21.5 | 25.6 | 44.4 | 49 |
TOTAL EXPENSES | 432.1 | 427.6 | 873.9 | 844.5 |
OPERATING INCOME (LOSS) | 35.2 | 94.8 | 153.9 | 210.6 |
Other Income (Expense): | ||||
Interest Income | 4.6 | 4.2 | 9.1 | 7.4 |
Allowance for Equity Funds Used During Construction | 2.5 | 4.5 | 4.6 | 6.8 |
Interest Expense | (27.8) | (27.1) | (55.5) | (49.6) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 14.5 | 76.4 | 112.1 | 175.2 |
Income Tax Expense (Credit) | 4 | 25.1 | 33.2 | 49.2 |
Net Income (Loss) | 10.5 | 51.3 | 78.9 | 126 |
Ohio Power Co [Member] | ||||
Revenues | ||||
Transmission and Distribution Utilities | 653.4 | 728.1 | 1,391.8 | 1,484.8 |
Sales to AEP Affiliates | 9.1 | 1.4 | 14.8 | 6.2 |
Other Revenues | 1.4 | 1.3 | 3.4 | 3.4 |
TOTAL REVENUES | 663.9 | 730.8 | 1,410 | 1,494.4 |
Expenses | ||||
Purchased Electricity for Resale | 156.4 | 147.8 | 344.7 | 312.7 |
Purchased Electricity from AEP Affiliates | 24.7 | 36.4 | 56.7 | 85.5 |
Amortization of Generation Deferrals | 53.3 | 51.8 | 114.2 | 106.9 |
Other Operation | 130.6 | 173.8 | 251.8 | 341.7 |
Maintenance | 33.3 | 31.9 | 70.5 | 65.6 |
Depreciation and Amortization | 51.1 | 58.3 | 108.4 | 119.6 |
Taxes Other Than Income Taxes | 94.9 | 92.2 | 193.4 | 189.8 |
TOTAL EXPENSES | 544.3 | 592.2 | 1,139.7 | 1,221.8 |
OPERATING INCOME (LOSS) | 119.6 | 138.6 | 270.3 | 272.6 |
Other Income (Expense): | ||||
Interest Income | 0.8 | 0.8 | 3.3 | 2.3 |
Carrying Costs Income | 0.6 | 1.2 | 2.5 | 3.1 |
Allowance for Equity Funds Used During Construction | 0.8 | 1.7 | 3.2 | 3.4 |
Interest Expense | (26.1) | (29.1) | (51.1) | (60.5) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 95.7 | 113.2 | 228.2 | 220.9 |
Income Tax Expense (Credit) | 33.4 | 38.6 | 79.7 | 76.1 |
Net Income (Loss) | 62.3 | 74.6 | 148.5 | 144.8 |
Public Service Co Of Oklahoma [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 342.6 | 298.6 | 644.5 | 570.4 |
Sales to AEP Affiliates | 1 | 0.9 | 2.1 | 1.9 |
Other Revenues | 1.1 | 0.7 | 2.2 | 2.2 |
TOTAL REVENUES | 344.7 | 300.2 | 648.8 | 574.5 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 25.6 | 11.1 | 37.9 | 26.6 |
Purchased Electricity for Resale | 126.7 | 91.2 | 252 | 184.5 |
Purchased Electricity from AEP Affiliates | 0 | 0.4 | 0 | 0.4 |
Other Operation | 75.3 | 67.9 | 142.7 | 130.8 |
Maintenance | 28.8 | 24.2 | 63 | 46 |
Depreciation and Amortization | 32.6 | 37.4 | 66.1 | 72.7 |
Taxes Other Than Income Taxes | 9.6 | 9 | 20.2 | 18.7 |
TOTAL EXPENSES | 298.6 | 241.2 | 581.9 | 479.7 |
OPERATING INCOME (LOSS) | 46.1 | 59 | 66.9 | 94.8 |
Other Income (Expense): | ||||
Interest Income | 0 | 0.1 | 0.1 | 0.3 |
Allowance for Equity Funds Used During Construction | 0 | 1.5 | 0.4 | 3.8 |
Interest Expense | (13.4) | (15.3) | (27) | (29.7) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 32.7 | 45.3 | 40.4 | 69.2 |
Income Tax Expense (Credit) | 12.3 | 16.4 | 15.2 | 24.6 |
Net Income (Loss) | 20.4 | 28.9 | 25.2 | 44.6 |
Southwestern Electric Power Co [Member] | ||||
Revenues | ||||
Vertically Integrated Utilities | 416 | 418.2 | 812.3 | 793.6 |
Sales to AEP Affiliates | 8.1 | 8.3 | 12.7 | 11.4 |
Other Revenues | 0.6 | 0.5 | 1 | 1 |
TOTAL REVENUES | 424.7 | 427 | 826 | 806 |
Expenses | ||||
Fuel and Other Consumables Used for Electric Generation | 111.4 | 122.6 | 242.3 | 244.5 |
Purchased Electricity for Resale | 46.3 | 33.5 | 78.7 | 61.6 |
Other Operation | 73.9 | 77 | 151.9 | 154.1 |
Maintenance | 41.7 | 37.1 | 73.9 | 68.2 |
Depreciation and Amortization | 52.1 | 49.4 | 102.9 | 96.9 |
Taxes Other Than Income Taxes | 24.3 | 21.5 | 47.6 | 43.4 |
TOTAL EXPENSES | 349.7 | 341.1 | 697.3 | 668.7 |
OPERATING INCOME (LOSS) | 75 | 85.9 | 128.7 | 137.3 |
Other Income (Expense): | ||||
Interest Income | 0.4 | 0 | 1.3 | 0 |
Allowance for Equity Funds Used During Construction | 0 | 2 | 0.8 | 9.4 |
Interest Expense | (30.9) | (31.5) | (60.8) | (59.4) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS) | 44.5 | 56.4 | 70 | 87.3 |
Income Tax Expense (Credit) | 13.2 | 13.3 | 22.7 | 20.7 |
Equity Earnings (Loss) of Unconsolidated Subsidiaries | (6.2) | 1.2 | (4.9) | 2.2 |
Net Income (Loss) | 25.1 | 44.3 | 42.4 | 68.8 |
Net Income Attributable to Noncontrolling Interests | 0.6 | 1.1 | 1.6 | 2.2 |
Earnings Attributable to Common Shareholders | $ 24.5 | $ 43.2 | $ 40.8 | $ 66.6 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Net Income (Loss) | $ 376.2 | $ 503.9 | $ 970.4 | $ 1,007 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 8.5 | 15.2 | (7.6) | 7.8 |
Securities Available for Sale, Net of Tax | 0.6 | 0.6 | 1.8 | 1.2 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | 0.3 | 0.1 | 0.5 | 0.2 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 9.4 | 15.9 | (5.3) | 9.2 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 385.6 | 519.8 | 965.1 | 1,016.2 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 1.2 | 1.8 | 3.2 | 3.7 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | 384.4 | 518 | 961.9 | 1,012.5 |
AEP Transmission Co [Member] | ||||
Net Income (Loss) | 107.4 | 74.8 | 164.4 | 100.6 |
Appalachian Power Co [Member] | ||||
Net Income (Loss) | 52.1 | 73.4 | 162.7 | 199.7 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (0.2) | (0.2) | (0.4) | (0.4) |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | (0.3) | (0.4) | (0.6) | (0.7) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (0.5) | (0.6) | (1) | (1.1) |
TOTAL COMPREHENSIVE INCOME (LOSS) | 51.6 | 72.8 | 161.7 | 198.6 |
Indiana Michigan Power Co [Member] | ||||
Net Income (Loss) | 10.5 | 51.3 | 78.9 | 126 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 0.4 | 0.3 | 0.7 | 0.7 |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 0.4 | 0.3 | 0.7 | 0.7 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 10.9 | 51.6 | 79.6 | 126.7 |
Ohio Power Co [Member] | ||||
Net Income (Loss) | 62.3 | 74.6 | 148.5 | 144.8 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (0.3) | (0.4) | (0.5) | (0.8) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (0.5) | (0.8) | ||
TOTAL COMPREHENSIVE INCOME (LOSS) | 62 | 74.2 | 148 | 144 |
Public Service Co Of Oklahoma [Member] | ||||
Net Income (Loss) | 20.4 | 28.9 | 25.2 | 44.6 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | (0.2) | (0.2) | (0.4) | (0.4) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | (0.4) | (0.4) | ||
TOTAL COMPREHENSIVE INCOME (LOSS) | 20.2 | 28.7 | 24.8 | 44.2 |
Southwestern Electric Power Co [Member] | ||||
Net Income (Loss) | 25.1 | 44.3 | 42.4 | 68.8 |
OTHER COMPREHENSIVE INCOME | ||||
Cash Flow Hedges, Net of Tax | 0.2 | 0.4 | 0.7 | 0.9 |
Amortization of Pension and OPEB Deferred Costs, Net of Tax | (0.1) | (0.2) | (0.3) | (0.4) |
TOTAL OTHER COMPREHENSIVE INCOME (LOSS) | 0.1 | 0.2 | 0.4 | 0.5 |
TOTAL COMPREHENSIVE INCOME (LOSS) | 25.2 | 44.5 | 42.8 | 69.3 |
Total Comprehensive Income Attributable to Noncontrolling Interest | 0.6 | 1.1 | 1.6 | 2.2 |
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS | $ 24.6 | $ 43.4 | $ 41.2 | $ 67.1 |
Consolidated Statements of Com4
Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Cash Flow Hedges, Tax | $ 4.6 | $ 8.2 | $ (4.1) | $ 4.2 |
Securities Available for Sale, Tax | 0.4 | 0.4 | 1 | 0.7 |
Amortization of Pension and OPEB Deferred Costs, Tax | 0.2 | 0 | 0.3 | 0.1 |
Appalachian Power Co [Member] | ||||
Cash Flow Hedges, Tax | (0.1) | (0.1) | (0.2) | (0.2) |
Amortization of Pension and OPEB Deferred Costs, Tax | (0.1) | (0.2) | (0.3) | (0.4) |
Indiana Michigan Power Co [Member] | ||||
Cash Flow Hedges, Tax | 0.2 | 0.2 | 0.4 | 0.4 |
Ohio Power Co [Member] | ||||
Cash Flow Hedges, Tax | (0.2) | (0.2) | (0.3) | (0.4) |
Public Service Co Of Oklahoma [Member] | ||||
Cash Flow Hedges, Tax | (0.1) | (0.1) | (0.2) | (0.2) |
Southwestern Electric Power Co [Member] | ||||
Cash Flow Hedges, Tax | 0.2 | 0.3 | 0.4 | 0.5 |
Amortization of Pension and OPEB Deferred Costs, Tax | $ (0.1) | $ (0.1) | $ (0.2) | $ (0.2) |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions | Total | AEP Transmission 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] | Common Stock [Member] | Common Stock [Member]Appalachian Power Co [Member] | Common Stock [Member]Indiana Michigan Power Co [Member] | Common Stock [Member]Ohio Power Co [Member] | Common Stock [Member]Public Service Co Of Oklahoma [Member] | Common Stock [Member]Southwestern Electric Power Co [Member] | Additional Paid-in Capital [Member] | Additional Paid-in Capital [Member]AEP Transmission Co [Member] | Additional Paid-in Capital [Member]Appalachian Power Co [Member] | Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member] | Additional Paid-in Capital [Member]Ohio Power Co [Member] | Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member] | Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member] | Retained Earnings [Member] | Retained Earnings [Member]AEP Transmission Co [Member] | Retained Earnings [Member]Appalachian Power Co [Member] | Retained Earnings [Member]Indiana Michigan Power Co [Member] | Retained Earnings [Member]Ohio Power Co [Member] | Retained Earnings [Member]Public Service Co Of Oklahoma [Member] | Retained Earnings [Member]Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member] | Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member] | Noncontrolling Interests [Member] | Noncontrolling Interests [Member]Southwestern Electric Power Co [Member] |
Beginning Balance at Dec. 31, 2015 | $ 1,552.9 | $ 1,243 | $ 309.9 | ||||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2015 | $ 17,904.9 | $ 3,475 | $ 2,036.4 | $ 1,986.6 | $ 1,119.9 | $ 2,169.7 | $ 3,324 | $ 260.4 | $ 56.6 | $ 321.2 | $ 157.2 | $ 135.7 | $ 6,296.5 | $ 1,828.7 | $ 980.9 | $ 838.8 | $ 364 | $ 676.6 | $ 8,398.3 | $ 1,388.7 | $ 1,015.6 | $ 822.3 | $ 594.5 | $ 1,366.3 | $ (127.1) | $ (2.8) | $ (16.7) | $ 4.3 | $ 4.2 | $ (9.4) | $ 13.2 | $ 0.5 | |||
Beginning Balance, Shares at Dec. 31, 2015 | 511,400,000 | ||||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||||||||
Issuance of Common Stock, Value | 30.9 | $ 4 | 26.9 | ||||||||||||||||||||||||||||||||
Issuance of Common Stock, Shares | 600,000 | ||||||||||||||||||||||||||||||||||
Common Stock Dividends | (553.1) | (550.8) | |||||||||||||||||||||||||||||||||
Common Stock Dividends | (150) | (62.5) | (150) | (60) | (150) | (62.5) | (150) | (60) | |||||||||||||||||||||||||||
Common Stock Dividends | (2.3) | (2.3) | (2.3) | ||||||||||||||||||||||||||||||||
Other Changes in Equity | 6 | 1.3 | 0.6 | 4.1 | |||||||||||||||||||||||||||||||
Capital Contributions from Member | 66.9 | 66.9 | |||||||||||||||||||||||||||||||||
Net Income (Loss) | 1,003.3 | 66.6 | 1,003.3 | 66.6 | |||||||||||||||||||||||||||||||
Net Income Attributable to Noncontrolling Interests | 3.7 | 2.2 | 3.7 | 2.2 | |||||||||||||||||||||||||||||||
Net Income (Loss) | 1,007 | 100.6 | 199.7 | 126 | 144.8 | 44.6 | 68.8 | 100.6 | 199.7 | 126 | 144.8 | 44.6 | |||||||||||||||||||||||
Other Comprehensive Income (Loss) | 9.2 | (1.1) | 0.7 | (0.8) | (0.4) | 0.5 | 9.2 | (1.1) | 0.7 | (0.8) | (0.4) | 0.5 | |||||||||||||||||||||||
Ending Balance at Jun. 30, 2016 | 1,720.4 | 1,309.9 | 410.5 | ||||||||||||||||||||||||||||||||
Ending Balance at Jun. 30, 2016 | 18,404.9 | 3,523.6 | 2,100.6 | 1,980.6 | 1,164.1 | 2,176.7 | $ 3,328 | 260.4 | 56.6 | 321.2 | 157.2 | 135.7 | 6,324.7 | 1,828.7 | 980.9 | 838.8 | 364 | 676.6 | 8,851.4 | 1,438.4 | 1,079.1 | 817.1 | 639.1 | 1,372.9 | (117.9) | (3.9) | (16) | 3.5 | 3.8 | (8.9) | 18.7 | 0.4 | |||
Ending Balance, Shares at Jun. 30, 2016 | 512,000,000 | ||||||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2016 | 1,957.6 | 1,455 | 502.6 | ||||||||||||||||||||||||||||||||
Beginning Balance at Dec. 31, 2016 | $ 17,420.1 | 3,583.5 | 2,151.8 | 2,117.5 | $ 1,214.1 | 2,215.2 | $ 3,328.3 | 260.4 | 56.6 | 321.2 | 157.2 | 135.7 | 6,332.6 | 1,828.7 | 980.9 | 838.8 | 364 | 676.6 | 7,892.4 | 1,502.8 | 1,130.5 | 954.5 | 689.5 | 1,411.9 | (156.3) | (8.4) | (16.2) | 3 | 3.4 | (9.4) | 23.1 | 0.4 | |||
Beginning Balance, Shares at Dec. 31, 2016 | 512,048,520 | 10,482,000 | 512,000,000 | ||||||||||||||||||||||||||||||||
Increase (Decrease) in Stockholders' Equity [Roll Forward] | |||||||||||||||||||||||||||||||||||
Common Stock Dividends | $ (584.9) | (583.2) | |||||||||||||||||||||||||||||||||
Common Stock Dividends | (60) | (62.5) | (130) | $ (35) | (55) | (60) | (62.5) | (130) | (35) | (55) | |||||||||||||||||||||||||
Common Stock Dividends | (1.7) | (1.7) | (1.7) | ||||||||||||||||||||||||||||||||
Other Changes in Equity | 49.2 | 48.4 | 0.8 | ||||||||||||||||||||||||||||||||
Capital Contributions from Member | 166.7 | 166.7 | |||||||||||||||||||||||||||||||||
Net Income (Loss) | 967.2 | 40.8 | 967.2 | 40.8 | |||||||||||||||||||||||||||||||
Net Income Attributable to Noncontrolling Interests | 3.2 | 1.6 | 3.2 | 1.6 | |||||||||||||||||||||||||||||||
Net Income (Loss) | 970.4 | 164.4 | 162.7 | 78.9 | 148.5 | 25.2 | 42.4 | 164.4 | 162.7 | 78.9 | 148.5 | 25.2 | |||||||||||||||||||||||
Other Comprehensive Income (Loss) | (5.3) | (1) | 0.7 | (0.5) | (0.4) | 0.4 | (5.3) | (1) | 0.7 | (0.5) | (0.4) | 0.4 | |||||||||||||||||||||||
Ending Balance at Jun. 30, 2017 | $ 2,288.7 | $ 1,621.7 | $ 667 | ||||||||||||||||||||||||||||||||
Ending Balance at Jun. 30, 2017 | $ 17,849.5 | $ 3,685.2 | $ 2,168.9 | $ 2,135.5 | $ 1,203.9 | $ 2,201.3 | $ 3,328.3 | $ 260.4 | $ 56.6 | $ 321.2 | $ 157.2 | $ 135.7 | $ 6,381 | $ 1,828.7 | $ 980.9 | $ 838.8 | $ 364 | $ 676.6 | $ 8,276.4 | $ 1,605.5 | $ 1,146.9 | $ 973 | $ 679.7 | $ 1,397.7 | $ (161.6) | $ (9.4) | $ (15.5) | $ 2.5 | $ 3 | $ (9) | $ 25.4 | $ 0.3 | |||
Ending Balance, Shares at Jun. 30, 2017 | 512,048,663 | 10,482,000 | 512,000,000 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 | |
Current Assets | |||
Cash and Cash Equivalents | $ 172.4 | $ 210.5 | |
Other Temporary Investments | 317.6 | 331.7 | |
Accounts Receivable: | |||
Customers | 538.7 | 705.1 | |
Accrued Unbilled Revenues | 122.1 | 158.7 | |
Pledged Accounts Receivable - AEP Credit | 949.4 | 972.7 | |
Miscellaneous | 90.5 | 118.1 | |
Allowance for Uncollectible Accounts | (38.9) | (37.9) | |
Total Accounts Receivable | 1,661.8 | 1,916.7 | |
Fuel | 427.2 | 423.8 | |
Materials and Supplies | 555 | 543.5 | |
Risk Management Assets | 170.5 | 94.5 | |
Regulatory Asset for Under-Recovered Fuel Costs | 189 | 156.6 | |
Margin Deposits | 91.1 | 79.9 | |
Assets Held for Sale | 0 | 1,951.2 | |
Prepayments and Other Current Assets | 224.4 | 325.5 | |
TOTAL CURRENT ASSETS | 3,809 | 6,033.9 | |
Property, Plant and Equipment | |||
Generation | 20,354.2 | 19,848.9 | |
Transmission | 17,481.2 | 16,658.7 | |
Distribution | 19,367 | 18,900.8 | |
Other Property, Plant and Equipment | 3,595.6 | 3,444.3 | |
Construction Work in Progress | 3,336.8 | 3,183.9 | |
Total Property, Plant and Equipment | 64,134.8 | 62,036.6 | |
Accumulated Depreciation and Amortization | 16,907.6 | 16,397.3 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 47,227.2 | 45,639.3 | |
Other Noncurrent Assets | |||
Regulatory Assets | 5,592.6 | 5,625.5 | |
Securitized Assets | 1,364.4 | 1,486.1 | |
Spent Nuclear Fuel and Decommissioning Trusts | 2,382 | 2,256.2 | |
Goodwill | 52.5 | 52.5 | |
Long-term Risk Management Assets | 285.6 | 289.1 | |
Deferred Charges and Other Noncurrent Assets | 2,025.8 | 2,085.1 | |
TOTAL OTHER NONCURRENT ASSETS | 11,702.9 | 11,794.5 | |
TOTAL ASSETS | 62,739.1 | 63,467.7 | |
Current Liabilities | |||
Accounts Payable | 1,268.4 | 1,688.5 | |
Short-term Debt: | |||
Securitized Debt for Receivables - AEP Credit | [1] | 519 | 673 |
Other Short-term Debt | 1,332.7 | 1,040 | |
Total Short-term Debt | 1,851.7 | 1,713 | |
Long-term Debt Due Within One Year | 2,755 | 2,878 | |
Risk Management Liabilities | 61.7 | 53.4 | |
Customer Deposits | 344 | 343.2 | |
Accrued Taxes | 891.5 | 1,048 | |
Accrued Interest | 217 | 227.2 | |
Regulatory Liability for Over-Recovered Fuel Costs | 17.1 | 8 | |
Liabilities Held for Sale | 0 | 235.9 | |
Other Current Liabilities | 985.8 | 1,302.8 | |
TOTAL CURRENT LIABILITIES | 8,392.2 | 9,498 | |
Noncurrent Liabilities | |||
Long-term Debt | 16,796.9 | 17,378.4 | |
Long-term Risk Management Liabilities | 310.6 | 316.2 | |
Deferred Income Taxes | 12,288.5 | 11,884.4 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 3,908.8 | 3,751.3 | |
Asset Retirement Obligations | 1,911 | 1,830.6 | |
Employee Benefits and Pension Obligations | 462.8 | 614.1 | |
Deferred Credits and Other Noncurrent Liabilities | 813.3 | 774.6 | |
TOTAL NONCURRENT LIABILITIES | 36,491.9 | 36,549.6 | |
TOTAL LIABILITIES | 44,884.1 | 46,047.6 | |
Rate Matters | |||
Commitments and Contingencies | |||
Mezzanine Equity | 5.5 | 0 | |
Equity | |||
Common Stock | 3,328.3 | 3,328.3 | |
Paid-in Capital | 6,381 | 6,332.6 | |
Retained Earnings | 8,276.4 | 7,892.4 | |
Accumulated Other Comprehensive Income (Loss) | (161.6) | (156.3) | |
TOTAL COMMON SHAREHOLDER'S EQUITY | 17,824.1 | 17,397 | |
Noncontrolling Interests | 25.4 | 23.1 | |
TOTAL EQUITY | 17,849.5 | 17,420.1 | |
TOTAL LIABILITIES AND EQUITY | 62,739.1 | 63,467.7 | |
AEP Transmission Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 0 | 0 | |
Advances to Affiliates | 22.2 | 67.1 | |
Accounts Receivable: | |||
Customers | 20.5 | 11.3 | |
Affiliated Companies | 94.4 | 66.6 | |
Total Accounts Receivable | 114.9 | 77.9 | |
Materials and Supplies | 10.9 | 5 | |
Accrued Tax Benefits | 10.4 | 26 | |
Prepayments and Other Current Assets | 7.5 | 2.8 | |
TOTAL CURRENT ASSETS | 165.9 | 178.8 | |
Property, Plant and Equipment | |||
Transmission | 4,383.9 | 3,973.5 | |
Other Property, Plant and Equipment | 109.4 | 99.4 | |
Construction Work in Progress | 1,197 | 981.3 | |
Total Property, Plant and Equipment | 5,690.3 | 5,054.2 | |
Accumulated Depreciation and Amortization | 133.1 | 99.6 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,557.2 | 4,954.6 | |
Other Noncurrent Assets | |||
Accounts Receivable, Related Parties, Noncurrent | 27.6 | 0 | |
Regulatory Assets | 133.5 | 112.3 | |
Deferred Tax Assets, Property, Plant and Equipment | 58.1 | 102.2 | |
Deferred Charges and Other Noncurrent Assets | 1.3 | 1.9 | |
TOTAL OTHER NONCURRENT ASSETS | 220.5 | 216.4 | |
TOTAL ASSETS | 5,943.6 | 5,349.8 | |
Current Liabilities | |||
Advances from Affiliates | 247.4 | 4.1 | |
Accounts Payable | 178.1 | 289.7 | |
Affiliated Companies | 45.8 | 43.1 | |
Short-term Debt: | |||
Accrued Taxes | 149.1 | 191.8 | |
Accrued Interest | 9.8 | 10.5 | |
Other Current Liabilities | 9.9 | 10.9 | |
TOTAL CURRENT LIABILITIES | 640.1 | 550.1 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,931.4 | 1,932 | |
Deferred Income Taxes | 1,008.2 | 862.1 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 54.5 | 44 | |
Deferred Credits and Other Noncurrent Liabilities | 20.7 | 4 | |
TOTAL NONCURRENT LIABILITIES | 3,014.8 | 2,842.1 | |
TOTAL LIABILITIES | 3,654.9 | 3,392.2 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Paid-in Captial | 1,621.7 | 1,455 | |
Retained Earnings | 667 | 502.6 | |
TOTAL MEMBER'S EQUITY | 2,288.7 | 1,957.6 | |
TOTAL LIABILITIES AND EQUITY | 5,943.6 | 5,349.8 | |
Appalachian Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 2.6 | 2.7 | |
Restricted Cash for Securitized Funding | 15.4 | 15.8 | |
Advances to Affiliates | 23.8 | 24.1 | |
Accounts Receivable: | |||
Customers | 106.9 | 131.4 | |
Affiliated Companies | 61.7 | 54.4 | |
Accrued Unbilled Revenues | 44.2 | 52.7 | |
Miscellaneous | 1.8 | 0.9 | |
Allowance for Uncollectible Accounts | (2.7) | (3.5) | |
Total Accounts Receivable | 211.9 | 235.9 | |
Fuel | 110.4 | 112 | |
Materials and Supplies | 100.3 | 98.8 | |
Risk Management Assets | 41.6 | 2.6 | |
Accrued Tax Benefits | 6.2 | 4.2 | |
Regulatory Asset for Under-Recovered Fuel Costs | 72.4 | 68.4 | |
Margin Deposits | 6.3 | 17.5 | |
Prepayments and Other Current Assets | 12.7 | 9.7 | |
TOTAL CURRENT ASSETS | 603.6 | 591.7 | |
Property, Plant and Equipment | |||
Generation | 6,389 | 6,332.8 | |
Transmission | 2,873.6 | 2,796.9 | |
Distribution | 3,657.6 | 3,569.1 | |
Other Property, Plant and Equipment | 403.2 | 373.5 | |
Construction Work in Progress | 397.8 | 390.3 | |
Total Property, Plant and Equipment | 13,721.2 | 13,462.6 | |
Accumulated Depreciation and Amortization | 3,762.8 | 3,636.8 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 9,958.4 | 9,825.8 | |
Other Noncurrent Assets | |||
Regulatory Assets | 1,106.9 | 1,121.1 | |
Securitized Assets | 293.7 | 305.3 | |
Deferred Charges and Other Noncurrent Assets | 131.3 | 133.3 | |
TOTAL OTHER NONCURRENT ASSETS | 1,531.9 | 1,559.7 | |
TOTAL ASSETS | 12,093.9 | 11,977.2 | |
Current Liabilities | |||
Advances from Affiliates | 124.7 | 79.6 | |
Accounts Payable | 212.5 | 253.7 | |
Affiliated Companies | 102.3 | 82.6 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 149 | 503.1 | |
Risk Management Liabilities | 0.4 | 0.3 | |
Customer Deposits | 83.1 | 83.1 | |
Accrued Taxes | 78.2 | 107.6 | |
Accrued Interest | 41 | 40.6 | |
Other Current Liabilities | 107.3 | 129.5 | |
TOTAL CURRENT LIABILITIES | 898.5 | 1,280.1 | |
Noncurrent Liabilities | |||
Long-term Debt | 3,841.5 | 3,530.8 | |
Long-term Risk Management Liabilities | 0.4 | 0.9 | |
Deferred Income Taxes | 2,756.3 | 2,672.3 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 633.2 | 627.8 | |
Asset Retirement Obligations | 107.5 | 108.8 | |
Employee Benefits and Pension Obligations | 92.2 | 108.5 | |
Deferred Credits and Other Noncurrent Liabilities | 79.1 | 64.5 | |
TOTAL NONCURRENT LIABILITIES | 7,510.2 | 7,113.6 | |
TOTAL LIABILITIES | 8,408.7 | 8,393.7 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Common Stock | 260.4 | 260.4 | |
Paid-in Capital | 1,828.7 | 1,828.7 | |
Retained Earnings | 1,605.5 | 1,502.8 | |
Accumulated Other Comprehensive Income (Loss) | (9.4) | (8.4) | |
TOTAL EQUITY | 3,685.2 | 3,583.5 | |
TOTAL LIABILITIES AND EQUITY | 12,093.9 | 11,977.2 | |
Indiana Michigan Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 1.1 | 1.2 | |
Advances to Affiliates | 12.6 | 12.5 | |
Accounts Receivable: | |||
Customers | 22.4 | 60.2 | |
Affiliated Companies | 56.9 | 51 | |
Accrued Unbilled Revenues | 0 | 1.5 | |
Miscellaneous | 0.7 | 0.7 | |
Allowance for Uncollectible Accounts | (0.1) | 0 | |
Total Accounts Receivable | 79.9 | 113.4 | |
Fuel | 41.5 | 32.3 | |
Materials and Supplies | 157.8 | 150.8 | |
Risk Management Assets | 15.8 | 3.5 | |
Accrued Tax Benefits | 19.4 | 37.7 | |
Regulatory Asset for Under-Recovered Fuel Costs | 10.9 | 26.1 | |
Accrued Reimbursement of Spent Nuclear Fuel Costs | 14.8 | 22.1 | |
Prepayments and Other Current Assets | 19 | 19.9 | |
TOTAL CURRENT ASSETS | 372.8 | 419.5 | |
Property, Plant and Equipment | |||
Generation | 4,227.8 | 4,056.1 | |
Transmission | 1,487.3 | 1,472.8 | |
Distribution | 1,965.6 | 1,899.3 | |
Other Property, Plant and Equipment | 571.6 | 550.2 | |
Construction Work in Progress | 592.4 | 654.2 | |
Total Property, Plant and Equipment | 8,844.7 | 8,632.6 | |
Accumulated Depreciation and Amortization | 3,014.1 | 3,005.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,830.6 | 5,627.5 | |
Other Noncurrent Assets | |||
Regulatory Assets | 901.6 | 916.6 | |
Spent Nuclear Fuel and Decommissioning Trusts | 2,382 | 2,256.2 | |
Deferred Charges and Other Noncurrent Assets | 104 | 121.5 | |
TOTAL OTHER NONCURRENT ASSETS | 3,387.6 | 3,294.3 | |
TOTAL ASSETS | 9,591 | 9,341.3 | |
Current Liabilities | |||
Advances from Affiliates | 43.4 | 215.2 | |
Accounts Payable | 173.6 | 179 | |
Affiliated Companies | 107.2 | 75.6 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 479.8 | 209.3 | |
Risk Management Liabilities | 0.9 | 0.3 | |
Customer Deposits | 36.6 | 34.3 | |
Accrued Taxes | 71.9 | 77.2 | |
Accrued Interest | 31.8 | 31.7 | |
Obligations Under Capital Leases | 8.3 | 9.4 | |
Other Current Liabilities | 99.7 | 123.4 | |
TOTAL CURRENT LIABILITIES | 1,053.2 | 955.4 | |
Noncurrent Liabilities | |||
Long-term Debt | 2,211.6 | 2,262.1 | |
Long-term Risk Management Liabilities | 0.2 | 0.8 | |
Deferred Income Taxes | 1,610.2 | 1,527.4 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 1,144.4 | 1,065.5 | |
Asset Retirement Obligations | 1,293.3 | 1,257.9 | |
Deferred Credits and Other Noncurrent Liabilities | 109.2 | 120.4 | |
TOTAL NONCURRENT LIABILITIES | 6,368.9 | 6,234.1 | |
TOTAL LIABILITIES | 7,422.1 | 7,189.5 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Common Stock | 56.6 | 56.6 | |
Paid-in Capital | 980.9 | 980.9 | |
Retained Earnings | 1,146.9 | 1,130.5 | |
Accumulated Other Comprehensive Income (Loss) | (15.5) | (16.2) | |
TOTAL EQUITY | 2,168.9 | 2,151.8 | |
TOTAL LIABILITIES AND EQUITY | 9,591 | 9,341.3 | |
Ohio Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 2.2 | 3.1 | |
Restricted Cash for Securitized Funding | 27.3 | 27.2 | |
Advances to Affiliates | 0 | 24.2 | |
Accounts Receivable: | |||
Customers | 55.4 | 51.1 | |
Affiliated Companies | 61.2 | 66.3 | |
Accrued Unbilled Revenues | 5.2 | 21 | |
Miscellaneous | 1.3 | 0.9 | |
Allowance for Uncollectible Accounts | (2.5) | (0.4) | |
Total Accounts Receivable | 120.6 | 138.9 | |
Materials and Supplies | 43.2 | 45.9 | |
Emission Allowances | 21.9 | 20.4 | |
Risk Management Assets | 0 | 0.2 | |
Accrued Tax Benefits | 47.9 | 0.1 | |
Prepayments and Other Current Assets | 20.6 | 10.9 | |
TOTAL CURRENT ASSETS | 283.7 | 270.9 | |
Property, Plant and Equipment | |||
Transmission | 2,337.7 | 2,319.2 | |
Distribution | 4,536.2 | 4,457.2 | |
Other Property, Plant and Equipment | 482.2 | 443.7 | |
Construction Work in Progress | 285.1 | 221.5 | |
Total Property, Plant and Equipment | 7,641.2 | 7,441.6 | |
Accumulated Depreciation and Amortization | 2,164.3 | 2,116 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,476.9 | 5,325.6 | |
Other Noncurrent Assets | |||
Notes Receivable - Affiliated | 32.3 | 32.3 | |
Regulatory Assets | 1,058 | 1,107.5 | |
Securitized Assets | 49.6 | 62.1 | |
Deferred Charges and Other Noncurrent Assets | 191.4 | 295.5 | |
TOTAL OTHER NONCURRENT ASSETS | 1,331.3 | 1,497.4 | |
TOTAL ASSETS | 7,091.9 | 7,093.9 | |
Current Liabilities | |||
Advances from Affiliates | 190.5 | 0 | |
Accounts Payable | 150.1 | 175.4 | |
Affiliated Companies | 120.4 | 95.6 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 396.8 | 46.4 | |
Risk Management Liabilities | 7.1 | 5.9 | |
Customer Deposits | 67.1 | 71 | |
Accrued Taxes | 315.6 | 520.3 | |
Accrued Interest | 31.1 | 31.2 | |
Other Current Liabilities | 185.1 | 236 | |
TOTAL CURRENT LIABILITIES | 1,463.8 | 1,181.8 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,345.7 | 1,717.5 | |
Long-term Risk Management Liabilities | 123.5 | 113.1 | |
Deferred Income Taxes | 1,438.7 | 1,346.1 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 521.2 | 506.2 | |
Employee Benefits and Pension Obligations | 19.5 | 27.8 | |
Deferred Credits and Other Noncurrent Liabilities | 44 | 83.9 | |
TOTAL NONCURRENT LIABILITIES | 3,492.6 | 3,794.6 | |
TOTAL LIABILITIES | 4,956.4 | 4,976.4 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Common Stock | 321.2 | 321.2 | |
Paid-in Capital | 838.8 | 838.8 | |
Retained Earnings | 973 | 954.5 | |
Accumulated Other Comprehensive Income (Loss) | 2.5 | 3 | |
TOTAL EQUITY | 2,135.5 | 2,117.5 | |
TOTAL LIABILITIES AND EQUITY | 7,091.9 | 7,093.9 | |
Public Service Co Of Oklahoma [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 1.4 | 1.5 | |
Accounts Receivable: | |||
Customers | 23.7 | 27.5 | |
Affiliated Companies | 27.4 | 26.8 | |
Miscellaneous | 2 | 4.4 | |
Allowance for Uncollectible Accounts | (0.2) | (0.2) | |
Total Accounts Receivable | 52.9 | 58.5 | |
Fuel | 15.5 | 22.9 | |
Materials and Supplies | 43.8 | 44.6 | |
Risk Management Assets | 9.5 | 0.8 | |
Accrued Tax Benefits | 22.8 | 27.3 | |
Regulatory Asset for Under-Recovered Fuel Costs | 63.4 | 33.8 | |
Prepayments and Other Current Assets | 7.6 | 6 | |
TOTAL CURRENT ASSETS | 216.9 | 195.4 | |
Property, Plant and Equipment | |||
Generation | 1,572.2 | 1,559.3 | |
Transmission | 846 | 832.8 | |
Distribution | 2,390.2 | 2,322.4 | |
Other Property, Plant and Equipment | 283.9 | 233.2 | |
Construction Work in Progress | 111.2 | 148.2 | |
Total Property, Plant and Equipment | 5,203.5 | 5,095.9 | |
Accumulated Depreciation and Amortization | 1,362.9 | 1,272.7 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 3,840.6 | 3,823.2 | |
Other Noncurrent Assets | |||
Regulatory Assets | 391.7 | 340.2 | |
Employee Benefits and Pension Assets | 15.9 | 10.4 | |
Deferred Charges and Other Noncurrent Assets | 28.5 | 10 | |
TOTAL OTHER NONCURRENT ASSETS | 436.1 | 360.6 | |
TOTAL ASSETS | 4,493.6 | 4,379.2 | |
Current Liabilities | |||
Advances from Affiliates | 141.4 | 52 | |
Accounts Payable | 104.2 | 116.3 | |
Affiliated Companies | 73.8 | 56.2 | |
Short-term Debt: | |||
Long-term Debt Due Within One Year | 0.5 | 0.5 | |
Customer Deposits | 52.5 | 49.7 | |
Accrued Taxes | 40.5 | 21 | |
Accrued Interest | 13.4 | 13.9 | |
Provision for Refund | 22.8 | 46.1 | |
Other Current Liabilities | 41.8 | 47.8 | |
TOTAL CURRENT LIABILITIES | 490.9 | 403.5 | |
Noncurrent Liabilities | |||
Long-term Debt | 1,285.8 | 1,285.5 | |
Deferred Income Taxes | 1,112.5 | 1,058.8 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 325.5 | 339.7 | |
Asset Retirement Obligations | 53.9 | 52.8 | |
Deferred Credits and Other Noncurrent Liabilities | 21.1 | 24.8 | |
TOTAL NONCURRENT LIABILITIES | 2,798.8 | 2,761.6 | |
TOTAL LIABILITIES | 3,289.7 | 3,165.1 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Common Stock | 157.2 | 157.2 | |
Paid-in Capital | 364 | 364 | |
Retained Earnings | 679.7 | 689.5 | |
Accumulated Other Comprehensive Income (Loss) | 3 | 3.4 | |
TOTAL EQUITY | 1,203.9 | 1,214.1 | |
TOTAL LIABILITIES AND EQUITY | 4,493.6 | 4,379.2 | |
Southwestern Electric Power Co [Member] | |||
Current Assets | |||
Cash and Cash Equivalents | 1.7 | 10.3 | |
Advances to Affiliates | 2 | 169.8 | |
Accounts Receivable: | |||
Customers | 20.5 | 48.5 | |
Affiliated Companies | 35.2 | 29.3 | |
Miscellaneous | 17.3 | 17.5 | |
Allowance for Uncollectible Accounts | (0.9) | (1.2) | |
Total Accounts Receivable | 72.1 | 94.1 | |
Fuel | 103.1 | 107.1 | |
Materials and Supplies | 69.3 | 68.4 | |
Risk Management Assets | 12.5 | 0.9 | |
Accrued Tax Benefits | 40.4 | 51.5 | |
Regulatory Asset for Under-Recovered Fuel Costs | 13.9 | 8.4 | |
Prepayments and Other Current Assets | 26.4 | 35.5 | |
TOTAL CURRENT ASSETS | 341.4 | 546 | |
Property, Plant and Equipment | |||
Generation | 4,618.7 | 4,607.6 | |
Transmission | 1,648.5 | 1,584.2 | |
Distribution | 2,061 | 2,020.6 | |
Other Property, Plant and Equipment | 699.3 | 670.4 | |
Construction Work in Progress | 116.1 | 113.8 | |
Total Property, Plant and Equipment | 9,143.6 | 8,996.6 | |
Accumulated Depreciation and Amortization | 2,634.4 | 2,567.1 | |
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 6,509.2 | 6,429.5 | |
Other Noncurrent Assets | |||
Regulatory Assets | 567.6 | 551.2 | |
Deferred Charges and Other Noncurrent Assets | 128.3 | 99.9 | |
TOTAL OTHER NONCURRENT ASSETS | 695.9 | 651.1 | |
TOTAL ASSETS | 7,546.5 | 7,626.6 | |
Current Liabilities | |||
Advances from Affiliates | 58.6 | 0 | |
Accounts Payable | 126.7 | 117.5 | |
Affiliated Companies | 80.1 | 68.5 | |
Short-term Debt: | |||
Other Short-term Debt | 8.7 | 0 | |
Long-term Debt Due Within One Year | 385.4 | 353.7 | |
Risk Management Liabilities | 0.5 | 0.3 | |
Customer Deposits | 62.2 | 62.1 | |
Accrued Taxes | 78.6 | 40.9 | |
Accrued Interest | 38.1 | 45.1 | |
Obligations Under Capital Leases | 11.3 | 11.8 | |
Other Current Liabilities | 70.5 | 83.9 | |
TOTAL CURRENT LIABILITIES | 920.7 | 783.8 | |
Noncurrent Liabilities | |||
Long-term Debt | 2,057.3 | 2,325.4 | |
Deferred Income Taxes | 1,681 | 1,606.9 | |
Regulatory Liabilities and Deferred Investment Tax Credits | 440.5 | 438.9 | |
Asset Retirement Obligations | 154.5 | 147.1 | |
Employee Benefits and Pension Obligations | 19.2 | 34.1 | |
Obligations Under Capital Leases | 62.1 | 65.5 | |
Deferred Credits and Other Noncurrent Liabilities | 9.9 | 9.7 | |
TOTAL NONCURRENT LIABILITIES | 4,424.5 | 4,627.6 | |
TOTAL LIABILITIES | 5,345.2 | 5,411.4 | |
Rate Matters | |||
Commitments and Contingencies | |||
Equity | |||
Common Stock | 135.7 | 135.7 | |
Paid-in Capital | 676.6 | 676.6 | |
Retained Earnings | 1,397.7 | 1,411.9 | |
Accumulated Other Comprehensive Income (Loss) | (9) | (9.4) | |
TOTAL COMMON SHAREHOLDER'S EQUITY | 2,201 | 2,214.8 | |
Noncontrolling Interests | 0.3 | 0.4 | |
TOTAL EQUITY | 2,201.3 | 2,215.2 | |
TOTAL LIABILITIES AND EQUITY | $ 7,546.5 | $ 7,626.6 | |
[1] | Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. |
Condensed Consolidated Balance7
Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Jun. 30, 2017 | Dec. 31, 2016 |
Current Assets | ||
Cash and Cash Equivalents | $ 172.4 | $ 210.5 |
Other Temporary Investments | 317.6 | 331.7 |
Fuel | 427.2 | 423.8 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 3,595.6 | 3,444.3 |
Accumulated Depreciation and Amortization | 16,907.6 | 16,397.3 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 2,755 | 2,878 |
Noncurrent Liabilities | ||
Long-term Debt | $ 16,796.9 | $ 17,378.4 |
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 | 512,048,663 | 512,048,520 |
Treasury Stock, Shares | 20,211,575 | 20,336,592 |
Appalachian Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 2.6 | $ 2.7 |
Fuel | 110.4 | 112 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 403.2 | 373.5 |
Accumulated Depreciation and Amortization | 3,762.8 | 3,636.8 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 149 | 503.1 |
Noncurrent Liabilities | ||
Long-term Debt | $ 3,841.5 | $ 3,530.8 |
Equity | ||
Common Stock, Shares Authorized | 30,000,000 | 30,000,000 |
Common Stock, Shares Outstanding | 13,499,500 | 13,499,500 |
Indiana Michigan Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | $ 1.1 | $ 1.2 |
Fuel | 41.5 | 32.3 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 571.6 | 550.2 |
Accumulated Depreciation and Amortization | 3,014.1 | 3,005.1 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 479.8 | 209.3 |
Noncurrent Liabilities | ||
Long-term Debt | $ 2,211.6 | $ 2,262.1 |
Equity | ||
Common Stock, No Par Value | $ 0 | $ 0 |
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 | $ 101.4 | $ 130.9 |
Ohio Power Co [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 2.2 | 3.1 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 482.2 | 443.7 |
Accumulated Depreciation and Amortization | 2,164.3 | 2,116 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 396.8 | 46.4 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,345.7 | $ 1,717.5 |
Equity | ||
Common Stock, No Par Value | $ 0 | $ 0 |
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 | $ 46.7 | $ 46.3 |
Noncurrent Liabilities | ||
Long-term Debt | 71.5 | 93.9 |
Public Service Co Of Oklahoma [Member] | ||
Current Assets | ||
Cash and Cash Equivalents | 1.4 | 1.5 |
Fuel | 15.5 | 22.9 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 283.9 | 233.2 |
Accumulated Depreciation and Amortization | 1,362.9 | 1,272.7 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 0.5 | 0.5 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,285.8 | $ 1,285.5 |
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 | $ 1.7 | $ 10.3 |
Fuel | 103.1 | 107.1 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 699.3 | 670.4 |
Accumulated Depreciation and Amortization | 2,634.4 | 2,567.1 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 385.4 | 353.7 |
Noncurrent Liabilities | ||
Long-term Debt | $ 2,057.3 | $ 2,325.4 |
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 | $ 0 | $ 8.7 |
Fuel | 44.1 | 34.3 |
Property, Plant and Equipment | ||
Other Property, Plant and Equipment | 268.9 | 267.5 |
Accumulated Depreciation and Amortization | 161.8 | 155.6 |
AEP Subsidiaries [Member] | ||
Current Assets | ||
Other Temporary Investments | 309 | 322.5 |
Current Liabilities | ||
Long-term Debt Due Within One Year | 404.6 | 427.5 |
Noncurrent Liabilities | ||
Long-term Debt | $ 1,552.2 | $ 1,737.5 |
Condensed Consolidated Stateme8
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Jun. 30, 2016 | |
Operating Activities | ||
Net Income (Loss) | $ 970.4 | $ 1,007 |
Income (Loss) from Discontinued Operations | 0 | (2.5) |
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 970.4 | 1,009.5 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 967.4 | 1,010.9 |
Deferred Income Taxes | 424.1 | 552.3 |
Asset Impairments and Other Related Charges | 13.1 | 0 |
Carrying Costs Income | (11.6) | (10.2) |
Allowance for Equity Funds Used During Construction | (42.2) | (60.5) |
Mark-to-Market of Risk Management Contracts | (84.7) | 48.7 |
Amortization of Nuclear Fuel | 71.6 | 73.2 |
Pension Contributions to Qualified Plan Trust | (93.3) | (84.8) |
Property Taxes | 122.9 | 131.3 |
Deferred Fuel Over/Under-Recovery, Net | 20.7 | (5.8) |
Gain on Sale of Merchant Generation Assets | (226.4) | 0 |
Recovery of Ohio Capacity Costs, Net | 47.1 | 67.4 |
Provision for Refund - Global Settlement | (88.1) | 0 |
Change in Other Noncurrent Assets | (201.1) | (201.2) |
Change in Other Noncurrent Liabilities | 132 | 1.8 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 270.5 | (166) |
Fuel, Materials and Supplies | (9.5) | (107) |
Accounts Payable | (170.5) | (22.6) |
Accrued Taxes, Net | (72.8) | (303.7) |
Other Current Assets | (45.3) | 26.3 |
Other Current Liabilities | (288.9) | (244) |
Net Cash Flows from (Used for) Operating Activities | 1,717 | 1,725.8 |
Construction Expenditures | (2,510.4) | (2,285.8) |
Change in Other Temporary Investments, Net | 13.5 | 80.9 |
Purchases of Investment Securities | (1,318.2) | (1,797.4) |
Sales of Investment Securities | 1,289.1 | 1,777 |
Acquisitions of Nuclear Fuel | (38.9) | (79.2) |
Proceeds from Sale of Merchant Generation Assets | 2,159.6 | 0 |
Other Investing Activities | 29.6 | 4.8 |
Net Cash Flows from (Used for) Investing Activities | (375.7) | (2,299.7) |
Financing Activities | ||
Issuance of Common Stock, Net | 0 | 30.9 |
Issuance of Long-term Debt | 1,050 | 743.4 |
Change in Short-term Debt, Net | 138.7 | 1,260.3 |
Retirement of Long-term Debt | (1,899.3) | (784.1) |
Make Whole Premium on Extinguishment of Long-term Debt | (44.9) | 0 |
Principal Payments for Capital Lease Obligations | (33.3) | (51) |
Dividends Paid on Common Stock | (584.9) | (553.1) |
Other Financing Activities | (5.7) | 0.4 |
Net Cash Flows from (Used for) Financing Activities | (1,379.4) | 646.8 |
Cash Flows from Discontinued Operations | ||
Operating Activities | 0 | (2.5) |
Investing Activities | 0 | 0 |
Financing Activities | 0 | 0 |
Net Increase (Decrease) in Cash and Cash Equivalents | (38.1) | 70.4 |
Cash and Cash Equivalents at Beginning of Period | 210.5 | 176.4 |
Cash and Cash Equivalents at End of Period | 172.4 | 246.8 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 442.3 | 425.4 |
Net Cash Paid (Received) for Income Taxes | (21.2) | 26.2 |
Noncash Acquisitions Under Capital Leases | 23.6 | 52.7 |
Construction Expenditures Included in Current Liabilities as of June 30, | 597.9 | 554.2 |
Construction Expenditures Included in Noncurrent Liabilities as of June 30, | 71.8 | 0 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, | 26 | 41.5 |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 2.4 | 0 |
AEP Transmission Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 164.4 | 100.6 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 46.1 | 30.7 |
Deferred Income Taxes | 134 | 107.1 |
Allowance for Equity Funds Used During Construction | (24.3) | (26.4) |
Property Taxes | 44.1 | 40.8 |
Long-term Accounts Receivable - Affiliated | (27.6) | 0 |
Change in Other Noncurrent Assets | (8.8) | (7.1) |
Change in Other Noncurrent Liabilities | 17 | 0.4 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | (37) | (38.1) |
Fuel, Materials and Supplies | (5.9) | 0 |
Accounts Payable | (2.7) | (8.4) |
Accrued Taxes, Net | (27.1) | 80.7 |
Accrued Interest | (0.7) | 0.3 |
Other Current Assets | (4.7) | 0 |
Other Current Liabilities | 1 | 0 |
Net Cash Flows from (Used for) Operating Activities | 267.8 | 280.6 |
Construction Expenditures | (721.2) | (527.4) |
Change in Advances to Affiliates, Net | 44.9 | 88.3 |
Other Investing Activities | (0.5) | (0.4) |
Net Cash Flows from (Used for) Investing Activities | (676.8) | (439.5) |
Financing Activities | ||
Capital Contributions from Member | 166.7 | 66.9 |
Change in Advances from Affiliates, Net | 243.3 | 92 |
Other Financing Activities | (1) | 0 |
Net Cash Flows from (Used for) Financing Activities | 409 | 158.9 |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | 0 | 0 |
Cash and Cash Equivalents at Beginning of Period | 0 | 0 |
Cash and Cash Equivalents at End of Period | 0 | 0 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 31.4 | 20.3 |
Net Cash Paid (Received) for Income Taxes | (67) | (178) |
Construction Expenditures Included in Current Liabilities as of June 30, | 190.3 | 155 |
Appalachian Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 162.7 | 199.7 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 201.3 | 191.9 |
Deferred Income Taxes | 86.2 | 68.3 |
Carrying Costs Income | (0.6) | (0.2) |
Allowance for Equity Funds Used During Construction | (3.5) | (4.6) |
Mark-to-Market of Risk Management Contracts | (39.4) | 24.2 |
Pension Contributions to Qualified Plan Trust | (10.2) | (8.8) |
Deferred Fuel Over/Under-Recovery, Net | (4) | 3.8 |
Change in Other Noncurrent Assets | 16.1 | (8.2) |
Change in Other Noncurrent Liabilities | 13.7 | (16.3) |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 24 | (16.7) |
Fuel, Materials and Supplies | 0.3 | (31.7) |
Accounts Payable | 18.7 | (13.5) |
Accrued Taxes, Net | (35.8) | 7.8 |
Other Current Assets | 8.5 | 3.5 |
Other Current Liabilities | (14.1) | (9.5) |
Net Cash Flows from (Used for) Operating Activities | 423.9 | 389.7 |
Construction Expenditures | (372.2) | (322.3) |
Change in Advances to Affiliates, Net | 0.3 | 1 |
Other Investing Activities | 10.9 | 9.5 |
Net Cash Flows from (Used for) Investing Activities | (361) | (311.8) |
Financing Activities | ||
Issuance of Long-term Debt | 320.9 | 249.2 |
Change in Advances from Affiliates, Net | 45.1 | (35.1) |
Retirement of Long-term Debt | (365.9) | (136.5) |
Principal Payments for Capital Lease Obligations | (3.5) | (3.1) |
Dividends Paid on Common Stock | (60) | (150) |
Other Financing Activities | 0.4 | 0.2 |
Net Cash Flows from (Used for) Financing Activities | (63) | (75.3) |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | (0.1) | 2.6 |
Cash and Cash Equivalents at Beginning of Period | 2.7 | 2.8 |
Cash and Cash Equivalents at End of Period | 2.6 | 5.4 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 92.4 | 90.9 |
Net Cash Paid (Received) for Income Taxes | 32 | 28.3 |
Noncash Acquisitions Under Capital Leases | 1.7 | 0.8 |
Construction Expenditures Included in Current Liabilities as of June 30, | 99.1 | 69.1 |
Indiana Michigan Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 78.9 | 126 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 99.8 | 94.1 |
Deferred Income Taxes | 74.4 | 86.8 |
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net | 31.6 | (20.6) |
Allowance for Equity Funds Used During Construction | (4.6) | (6.8) |
Mark-to-Market of Risk Management Contracts | (12.3) | 3.1 |
Amortization of Nuclear Fuel | 71.6 | 73.2 |
Pension Contributions to Qualified Plan Trust | (13) | (12.7) |
Deferred Fuel Over/Under-Recovery, Net | 25.3 | 4.9 |
Change in Other Noncurrent Assets | (26.4) | (1.9) |
Change in Other Noncurrent Liabilities | 34.8 | 17.9 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 33.5 | (6) |
Fuel, Materials and Supplies | (15.2) | (19.3) |
Accounts Payable | 9 | (26.8) |
Accrued Taxes, Net | 13 | (9.2) |
Other Current Assets | 15.9 | 8 |
Other Current Liabilities | (27.1) | (19.7) |
Net Cash Flows from (Used for) Operating Activities | 389.2 | 291 |
Construction Expenditures | (304.4) | (258.9) |
Change in Advances to Affiliates, Net | (0.1) | (0.7) |
Purchases of Investment Securities | (1,317.2) | (1,796.4) |
Sales of Investment Securities | 1,289.1 | 1,777 |
Acquisitions of Nuclear Fuel | (38.9) | (79.2) |
Other Investing Activities | 3.4 | 4 |
Net Cash Flows from (Used for) Investing Activities | (368.1) | (354.2) |
Financing Activities | ||
Issuance of Long-term Debt | 411.5 | 482.7 |
Change in Advances from Affiliates, Net | (171.8) | (282.9) |
Retirement of Long-term Debt | (193.3) | (53.5) |
Principal Payments for Capital Lease Obligations | (5.9) | (19.8) |
Dividends Paid on Common Stock | (62.5) | (62.5) |
Other Financing Activities | 0.8 | 0.6 |
Net Cash Flows from (Used for) Financing Activities | (21.2) | 64.6 |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | (0.1) | 1.4 |
Cash and Cash Equivalents at Beginning of Period | 1.2 | 1.1 |
Cash and Cash Equivalents at End of Period | 1.1 | 2.5 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 49.2 | 40.3 |
Net Cash Paid (Received) for Income Taxes | (56.9) | (23.6) |
Noncash Acquisitions Under Capital Leases | 2.6 | 16.5 |
Construction Expenditures Included in Current Liabilities as of June 30, | 96 | 89.8 |
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, | 26 | 41.5 |
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 2.5 | 0.1 |
Ohio Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 148.5 | 144.8 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 108.4 | 119.6 |
Amortization Of Generation Deferrals | 114.2 | 106.9 |
Deferred Income Taxes | 94.5 | 20.6 |
Carrying Costs Income | (2.5) | (3.1) |
Allowance for Equity Funds Used During Construction | (3.2) | (3.4) |
Mark-to-Market of Risk Management Contracts | 11.8 | 30.2 |
Pension Contributions to Qualified Plan Trust | (8.2) | (7.1) |
Property Taxes | 117.2 | 113.2 |
Provision for Refund - Global Settlement | (88.1) | 0 |
Change in Other Noncurrent Assets | (93.1) | (36.2) |
Change in Other Noncurrent Liabilities | 41.8 | 8.6 |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 18.3 | 8.6 |
Fuel, Materials and Supplies | (7.4) | (3) |
Accounts Payable | (6.8) | (4.8) |
Accrued Taxes, Net | (252.5) | (226.8) |
Other Current Assets | (9.6) | (3.4) |
Other Current Liabilities | (25.3) | (58.9) |
Net Cash Flows from (Used for) Operating Activities | 158 | 205.8 |
Construction Expenditures | (224.5) | (193.2) |
Change in Restricted Cash for Securitized Funding | (0.1) | 0.5 |
Change in Advances to Affiliates, Net | 24.2 | 331.1 |
Other Investing Activities | 4.9 | 6.2 |
Net Cash Flows from (Used for) Investing Activities | (195.5) | 144.6 |
Financing Activities | ||
Change in Advances from Affiliates, Net | 190.5 | 177.1 |
Retirement of Long-term Debt | (22.5) | (372.8) |
Principal Payments for Capital Lease Obligations | (2) | (2) |
Dividends Paid on Common Stock | (130) | (150) |
Other Financing Activities | 0.6 | 0.5 |
Net Cash Flows from (Used for) Financing Activities | 36.6 | (347.2) |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | (0.9) | 3.2 |
Cash and Cash Equivalents at Beginning of Period | 3.1 | 3.1 |
Cash and Cash Equivalents at End of Period | 2.2 | 6.3 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 50 | 60 |
Net Cash Paid (Received) for Income Taxes | 76.8 | 132.3 |
Noncash Acquisitions Under Capital Leases | 1.9 | 1.7 |
Construction Expenditures Included in Current Liabilities as of June 30, | 50.3 | 23.1 |
Public Service Co Of Oklahoma [Member] | ||
Operating Activities | ||
Net Income (Loss) | 25.2 | 44.6 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 66.1 | 72.7 |
Deferred Income Taxes | 53.7 | 62.6 |
Allowance for Equity Funds Used During Construction | (0.4) | (3.8) |
Mark-to-Market of Risk Management Contracts | (8.7) | (0.7) |
Pension Contributions to Qualified Plan Trust | (5.3) | (5.6) |
Property Taxes | (18.9) | (16) |
Deferred Fuel Over/Under-Recovery, Net | (29.6) | (33.5) |
Provision for Refund | (23.3) | 11.8 |
Change in Other Noncurrent Assets | (18.6) | (14.2) |
Change in Other Noncurrent Liabilities | (0.7) | (15.2) |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 5.6 | (3.8) |
Fuel, Materials and Supplies | 8.2 | (5.6) |
Accounts Payable | 9 | 27 |
Accrued Taxes, Net | 24 | 21.6 |
Other Current Assets | (1.2) | (1.1) |
Other Current Liabilities | (2.7) | 4.6 |
Net Cash Flows from (Used for) Operating Activities | 82.4 | 145.4 |
Construction Expenditures | (136.2) | (194) |
Change in Advances to Affiliates, Net | 0 | 47.1 |
Other Investing Activities | 1.3 | 5.1 |
Net Cash Flows from (Used for) Investing Activities | (134.9) | (141.8) |
Financing Activities | ||
Change in Advances from Affiliates, Net | 89.4 | 0 |
Retirement of Long-term Debt | (0.2) | (0.2) |
Principal Payments for Capital Lease Obligations | (2) | (1.8) |
Dividends Paid on Common Stock | (35) | 0 |
Other Financing Activities | 0.2 | 0.3 |
Net Cash Flows from (Used for) Financing Activities | 52.4 | (1.7) |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | (0.1) | 1.9 |
Cash and Cash Equivalents at Beginning of Period | 1.5 | 1.4 |
Cash and Cash Equivalents at End of Period | 1.4 | 3.3 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 31.7 | 30.2 |
Net Cash Paid (Received) for Income Taxes | (42.9) | (42) |
Noncash Acquisitions Under Capital Leases | 0.9 | 1.6 |
Construction Expenditures Included in Current Liabilities as of June 30, | 29.2 | 24.3 |
Southwestern Electric Power Co [Member] | ||
Operating Activities | ||
Net Income (Loss) | 42.4 | 68.8 |
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities: | ||
Depreciation and Amortization | 102.9 | 96.9 |
Deferred Income Taxes | 68.7 | 96.6 |
Allowance for Equity Funds Used During Construction | (0.8) | (9.4) |
Mark-to-Market of Risk Management Contracts | (11.4) | (3.2) |
Pension Contributions to Qualified Plan Trust | (8.9) | (8.3) |
Property Taxes | (30.8) | (27.4) |
Deferred Fuel Over/Under-Recovery, Net | (3.1) | 5.4 |
Change in Other Noncurrent Assets | (3.3) | 11.8 |
Change in Other Noncurrent Liabilities | (11.1) | (11) |
Changes in Certain Components of Working Capital: | ||
Accounts Receivable, Net | 22 | 2.5 |
Fuel, Materials and Supplies | 3.1 | 16.8 |
Accounts Payable | 13.2 | (1) |
Accrued Taxes, Net | 48.8 | (7.5) |
Other Current Assets | 9.3 | (2.7) |
Other Current Liabilities | (24.1) | (21.2) |
Net Cash Flows from (Used for) Operating Activities | 216.9 | 207.1 |
Construction Expenditures | (164.7) | (220.7) |
Change in Advances to Affiliates, Net | 167.8 | 0 |
Other Investing Activities | 3.3 | (2.2) |
Net Cash Flows from (Used for) Investing Activities | 6.4 | (222.9) |
Financing Activities | ||
Issuance of Long-term Debt | 114.7 | 0 |
Change in Short-term Debt, Net | 8.7 | 0 |
Change in Advances from Affiliates, Net | 58.6 | 96.8 |
Retirement of Long-term Debt | (351.8) | (1.6) |
Principal Payments for Capital Lease Obligations | (5.7) | (9.3) |
Dividends Paid on Common Stock | (55) | (60) |
Dividends Paid on Common Stock | (1.7) | (2.3) |
Other Financing Activities | 0.3 | 1 |
Net Cash Flows from (Used for) Financing Activities | (231.9) | 24.6 |
Cash Flows from Discontinued Operations | ||
Net Increase (Decrease) in Cash and Cash Equivalents | (8.6) | 8.8 |
Cash and Cash Equivalents at Beginning of Period | 10.3 | 5.2 |
Cash and Cash Equivalents at End of Period | 1.7 | 14 |
Supplementary Information | ||
Cash Paid for Interest, Net of Capitalized Amounts | 66.8 | 57.5 |
Net Cash Paid (Received) for Income Taxes | (56.5) | (29.4) |
Noncash Acquisitions Under Capital Leases | 1.8 | 5.3 |
Construction Expenditures Included in Current Liabilities as of June 30, | $ 50.6 | $ 68.9 |
Significant Accounting Matters
Significant Accounting Matters | 6 Months Ended |
Jun. 30, 2017 | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
AEP Transmission Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Appalachian Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Indiana Michigan Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Ohio Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Public Service Co Of Oklahoma [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Southwestern Electric Power Co [Member] | |
Significant Accounting Matters | SIGNIFICANT ACCOUNTING MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present AEP’s basic and diluted EPS calculations included on the statements of income: Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 There were no antidilutive shares outstanding as of June 30, 2017 and 2016 . Nonconsolidated Variable Interest Entity (Applies to AEP and SWEPCo) SWEPCo recorded prior year income tax adjustments in the current period related to DHLC that impacted Equity Earnings (Loss) of Unconsolidated Subsidiary in the amount of $6.3 million . Supplementary Cash Flow Information (Applies to AEP) Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
New Accounting Pronouncements
New Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2017 | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
AEP Transmission Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Appalachian Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Indiana Michigan Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Ohio Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Public Service Co Of Oklahoma [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Southwestern Electric Power Co [Member] | |
New Accounting Pronouncements | NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016 and 2017, revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Evaluation of revenue streams and new contracts continues during the second half of 2017. Given industry conclusions related to implementation issues, including contributions in aid of construction and collectability, management does not anticipate changes to current accounting systems. Management will also continue to monitor any industry implementation issues that arise and analyze the related impacts to revenue recognition. Management plans to adopt ASU 2014-09 effective January 1, 2018. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016 and 2017, lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Multiple lease system options were also evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Evaluation of new lease contracts continues and a compliant lease system solution will be implemented during the second half of 2017. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. Management adopted ASU 2016-09 effective January 1, 2017. As a result of the adoption of this guidance, management made an accounting policy election to recognize the effect of forfeitures in compensation cost when they occur. There was an immaterial impact on results of operations and financial position and no impact on cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report. ASU 2017-07 “Compensation - Retirement Benefits” (ASU 2017-07) In March 2017, the FASB issued ASU 2017-07 requiring that an employer report the service cost component of pension and postretirement benefits in the same line item or items as other compensation costs. The other components of net benefit cost are required to be presented in the income statement separately from the service cost component and outside of a subtotal of income from operations. In addition, only the service cost component will be eligible for capitalization as applicable following labor. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted as of the beginning of an annual period for which financial statements have not been issued or made available for issuance. Management is analyzing the impact of the new standard and assessing an implementation program which will likely require changes in the way accounting systems capture and report the required information. Unresolved industry implementation issues also continue to be monitored, including balance sheet presentation when a credit related to the non-service cost components is greater than service cost component. Management plans to adopt ASU 2017-07 effective January 1, 2018. |
Comprehensive Income
Comprehensive Income | 6 Months Ended |
Jun. 30, 2017 | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Appalachian Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Indiana Michigan Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Ohio Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Public Service Co Of Oklahoma [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Southwestern Electric Power Co [Member] | |
Comprehensive Income | COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants except for AEPTCo. AEPTCo does not have a component of other comprehensive income. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the three and six months ended June 30, 2017 and 2016 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 7 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Rate Matters
Rate Matters | 6 Months Ended |
Jun. 30, 2017 | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
AEP Transmission Co [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Appalachian Power Co [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Indiana Michigan Power Co [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Ohio Power Co [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Public Service Co Of Oklahoma [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Southwestern Electric Power Co [Member] | |
Rate Matters | RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. As discussed in AEP’s and AEPTCo’s 2016 Annual Reports, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within AEP’s and AEPTCo’s 2016 Annual Reports 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 2017 and updates AEP’s and AEPTCo’s 2016 Annual Reports. Regulatory Assets Pending Final Regulatory Approval AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million . (b) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 (a) In 2015, APCo recorded a $91 million reduction to accumulated depreciation related to the remaining net book value of plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements at the end of their depreciable lives under the group composite method of depreciation. Recovery of the remaining Virginia net book value for the retired plants will be considered in APCo’s next depreciation study which will be included in APCo’s 2018-2019 Virginia biennial filing in March 2020. I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 (a) In March 2017, $41 million was reclassified from accumulated depreciation to regulatory assets related to Northeastern Plant, Unit 3. As of June 30, 2017 , the unrecovered plant balance related to Northeastern Plant, Unit 3 was $46 million. SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition. AEP Texas Rate Matters (Applies to AEP) AEP Texas Interim Transmission and Distribution Rates As of June 30, 2017 , AEP Texas’ cumulative revenues from interim base rate increases from 2008 through 2017, subject to review, are estimated to be $635 million . A base rate review could produce a refund if AEP Texas incurs a disallowance of the transmission or distribution investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission and distribution rates, could reduce future net income and cash flows and impact financial condition. APCo Rate Matters (Applies to AEP and APCo) Virginia Legislation Affecting Biennial Reviews In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo’s financial statements adequately address the impact of these amendments. The amendments provide that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred from 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential asset impairments related to new carbon emission guidelines issued by the Federal EPA. In 2016, the Virginia SCC issued an order that denied the petition of certain APCo industrial customers that requested the issuance of a declaratory order that would find the amendments to Virginia law suspending biennial reviews unconstitutional and, accordingly, direct APCo to make biennial review filings beginning in 2016. In July 2016, the industrial customers filed an appeal of the order with the Supreme Court of Virginia. In April 2017, oral arguments were held before the Supreme Court of Virginia. Management is unable to predict the outcome of these challenges to the Virginia legislation. If the biennial review process is reinstated in advance of March 2020, it could reduce future net income and cash flows and impact financial condition. ETT Rate Matters (Applies to AEP) ETT Interim Transmission Rates Parent has a 50% equity ownership interest in ETT. Predominantly all of ETT’s revenues are based on interim rate changes that can be filed twice annually and are subject to review and possible true-up in the next filed base rate proceeding. Through June 30, 2017 , AEP’s share of ETT’s cumulative revenues that are subject to review is estimated to be $672 million . A base rate review could produce a refund if ETT incurs a disallowance of the transmission investment on which an interim increase was based. Management is unable to determine a range of potential losses, if any, that are reasonably possible of occurring. A revenue decrease, including a refund of interim transmission rates, could reduce future net income and cash flows and impact financial condition. I&M Rate Matters (Applies to AEP and I&M) 2017 Indiana Base Rate Case In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return on common equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase would be subject to an offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment rider related to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 million related to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and Rockport Plant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Life Cycle Management Project. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Michigan Base Rate Case In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6% return on common equity with the increase to be implemented no later than March 2018. The proposed annual increase includes $23 million related to increased annual depreciation rates and a $4 million increase related primarily to the amortization of certain Cook Plant regulatory assets. The increase in depreciation rates is primarily due to the change in the expected retirement date for Rockport Plant, Unit 1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, the total proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetation management expenses. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. As of June 30, 2017 , total costs incurred related to this project, including AFUDC, is approximately $9 million . The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using the existing Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of the proposed SCR project will be billable under the Rockport Unit Power Agreement to affiliates, including I&M, with I&M’s share recoverable in its base rates. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a request with the U.S. District Court for the Southern District of Ohio to delay the existing deadline for installation of SCR technology at Rockport Plant, Unit 2. KPCo Rate Matters (Applies to AEP) 2017 Kentucky Base Rate Case In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed 10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase includes: (a) lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currently recovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy, Unit 1 depreciation rates using a proposed retirement date of 2031, (d) recovery of other Big Sandy, Unit 1 generation costs currently recovered through a retail rider and (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surcharge revenues. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. OPCo Rate Matters (Applies to AEP and OPCo) Ohio Electric Security Plan Filings June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024 In 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal also involved a PPA rider that would include OPCo’s OVEC contractual entitlement (OVEC PPA) and would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. In 2015, the PUCO issued orders that approved OPCo’s ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The orders included: (a) approval of the DIR, with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo’s proposed OVEC PPA and (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal. Also in 2015, OPCo subsequently filed an amended OVEC PPA application that, among other things, addressed certain PPA requirements set forth in a 2015 PUCO order. In 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments. In 2016, the PUCO issued orders that approved a contested stipulation agreement related to the PPA rider application. Additionally, as part of these orders, the PUCO approved (a) recovery of OVEC-related net margin incurred beginning June 2016, (b) potential additional contingent customer credits of up to $15 million to be included in the PPA rider over the final four years of the PPA rider and (c) the limitation that OPCo will not flow through any capacity performance penalties or bonuses through the PPA rider. Additionally, subject to cost recovery and PUCO approval, OPCo agreed to develop and implement, by 2021, a solar energy project(s) of at least 400 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 2017, the PUCO rejected all pending rehearing requests and the orders are all now final. In June 2017, intervenors filed appeals to the Supreme Court of Ohio stating that the PUCO’s approval of the OVEC PPA was unlawful and does not provide customers with rate stability. In November 2016, OPCo refiled its amended ESP extension application and supporting testimony, consistent with the terms of the modified and approved stipulation agreement and based upon a 2016 PUCO order. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. A hearing at the PUCO is scheduled for August 2017. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. 2016 SEET Filing Ohio law provides for the return of significantly excessive earnings to ratepayers upon PUCO review. Significantly excessive earnings are measured by whether the earned return on common equity of the electric utility is significantly in excess of the return on common equity that was earned during the same period by publicly traded companies, including utilities, that face comparable business and financial risk. In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in the comparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, management excluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers related to the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings. In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantly excessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group. Although management believes that OPCo’s 2016 earnings were not excessive, management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s SEET treatment of the Global Settlement issues described above or adopt a different 2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impact financial condition. PSO Rate Matters (Applies to AEP and PSO) 2017 Oklahoma Base Rate Case In June 2017, PSO filed an application for a base rate review with the OCC that requested a net increase in annual revenues of $156 million based upon a proposed 10% return on common equity. The proposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmental compliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure deployment cost, (c) additional capital investments and customer costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter service lives and lower net salvage estimates. As part of this filing, PSO also requested recovery through 2040 of the net book value of Northeastern Plant, Unit 4 that was retired in 2016. As of June 30, 2017 , the net book value of Northeastern Plant, Unit 4 was $83 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. SWEPCo Rate Matters (Applies to AEP and SWEPCo) 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 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. Upon rehearing in 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 was approximately $52 million . In 2014, intervenors filed appeals of that order with the Texas District Court and SWEPCo intervened in those appeals. In June 2017, the Texas District Court upheld the PUCT’s 2014 order. In July 2017, an intervenor filed a notice of appeal with the Texas District Court. If certain parts of the PUCT order are overturned and if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, it could reduce future net income and cash flows and impact financial condition. 2016 Texas Base Rate Case In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10% return on common equity. The annual increase includes approximately (a) $34 million related to additional environmental controls, including those installed at the Welsh Plant, to comply with Federal EPA mandates, (b) $25 million for additional generation, transmission and distribution investments and increased operating costs, (c) $8 million related to transmission cost recovery within SWEPCo’s regional transmission organization and (d) $2 million in additional vegetation management. As part of this filing, SWEPCo requested recovery of the Texas jurisdictional share (approximately 33% ) of the net book value of Welsh Plant, Unit 2 through 2042, the remaining life of Welsh Plant, Unit 3. In April and May 2017, various intervenors and the PUCT staff filed testimony that included annual net revenue increase recommendations ranging from $36 million to $47 million . The recommended return on common equity ranged from 9.2% to 9.35% . In addition, no parties recommended approval of SWEPCo’s proposed transmission cost recovery and certain parties recommended investment disallowances that could result in write-offs of up to approximately $89 million , including approximately $40 million related to environmental investments and $25 million related to Welsh Plant, Unit 2. A hearing at the PUCT was held in June 2017. If any of these costs are not recoverable, including environmental investments and retirement-related costs for Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. Louisiana Turk Plant Prudence Review Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant, have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed into service in December 2012. A hearing at the LPSC related to the Turk Plant prudence review is scheduled for November 2017. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which was effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2017 Louisiana Formula Rate Filing In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million , which was effective May 2017 and includes Louisiana’s jurisdictional share of Welsh and Flint Creek environmental controls which were placed in service in 2016. These environmental costs are subject to prudence review. The $31 million net annual increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant - Environmental Impact Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for Welsh Plant, Units 1 and 3 could total approximately $850 million , excluding AFUDC. As of June 30, 2017 , SWEPCo had incurred costs of $398 million , including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules and related project cost estimates. As of June 30, 2017 , the total net book value of Welsh Plant, Units 1 and 3 was $628 million , before cost of removal, including materials and supplies inventory and CWIP. In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of these environmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In December 2016, the LPSC approved deferral of certain expenses related to the Louisiana jurisdictional share of environmental controls installed at Welsh Plant. In April 2017, the LPSC approved SWEPCo’s recovery of these deferred costs effective May 2017. The approved Louisiana jurisdictional share of Welsh Plant deferrals were $11 million , excluding $6 million of unrecognized equity, subject to review by the LPSC, and include a WACC return on environmental investments and the related depreciation expense and taxes. Effective May 2017, SWEPCo began recovering $131 million in investments related to Louisiana’s jurisdictional share of environmental costs. SWEPCo has sought recovery of its project costs from retail customers at the PUCT and is recovering these costs from wholesale customers through their FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing” disclosures above. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Rate Matters PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In June 2016, PJM transmission owners, including the eastern AEP affiliates, and various state commissions filed a settlement agreement with the FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. In July 2016, certain parties filed comments at the FERC contesting the settlement agreement. Upon final FERC approval, PJM would implement a transmission enhancement charge adjustment through the PJM OATT, billable through 2025. Management expects that any refunds received would generally be returned to retail customers through existing state rider mechanisms. FERC Transmission Complaint - AEP’s PJM Participants (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In October 2016, several parties filed a joint complaint with the FERC that states the base return on common equity used by eastern AEP affiliates in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99% to 8.32% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. Modifications to AEP’s PJM Transmission Rates (Applies to AEP, AEPTCo, APCo, I&M and OPCo) In November 2016, certain AEP affiliates filed an application with the FERC to modify the PJM OATT formula transmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to estimated expenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matter for hearing and settlement procedures. Effective January 1, 2017, the modified PJM OATT formula rates were implemented, subject to refund, based on projected 2017 calendar year financial activity and projected plant balances. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. FERC Transmission Complaint - AEP’s SPP Participants (Applies to AEP, AEPTCo, PSO and SWEPCo) In June 2017, several parties filed a joint complaint with the FERC that states the base return on common equity used by western AEP affiliates in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7% to 8.36% , effective upon the date of the complaint. Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition. |
Commitments, Guarantees and Con
Commitments, Guarantees and Contingencies | 6 Months Ended |
Jun. 30, 2017 | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
AEP Transmission Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Appalachian Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Indiana Michigan Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Ohio Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Public Service Co Of Oklahoma [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Southwestern Electric Power Co [Member] | |
Commitments, Guarantees and Contingencies | COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants 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 the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within AEP’s and AEPTCo’s 2016 Annual Reports 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 (Applies to AEP and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has a $3 billion revolving credit facility due in June 2021, under which up to $1.2 billion may be issued as letters of credit on behalf of subsidiaries. In May 2017, the $500 million revolving credit facility due in June 2018 was terminated. As of June 30, 2017 , no letters of credit were issued under the $3 billion revolving credit facility. An uncommitted facility gives the issuer of the facility the right to accept or decline each request made under the facility. AEP also issues letters of credit on behalf of subsidiaries under four uncommitted facilities totaling $370 million . In April 2017, the $75 million credit facility due in October 2017 was amended to $100 million due in April 2019. As of June 30, 2017 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 AEP has $45 million of variable rate Pollution Control Bonds supported by $46 million of bilateral letters of credit maturing in July 2019. Guarantees of Third-Party Obligations (Applies to AEP and 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. It is estimated the reserves will be depleted in 2036 with final reclamation completed by 2046 at an estimated cost of $74 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2017 , SWEPCo has collected $70 million through a rider for final mine closure and reclamation costs, of which $74 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of June 30, 2017 , the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants 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 June 30, 2017 , 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 AEP companies related to power purchase and sale activity. 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. Master Lease Agreements The Registrants 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 Registrants 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 June 30, 2017 , the maximum potential loss by Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 Railcar Lease (Applies to AEP, I&M and SWEPCo) 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 $8 million and $9 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2017 . 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 83% of the projected fair value of the equipment under the current five -year lease term to 77% at the end of the 20 -year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of June 30, 2017 , 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. AEPRO Boat and Barge Leases (Applies to AEP) In October 2015, AEP signed a Purchase and Sale Agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated party. The sale closed in November 2015. Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2027. As of June 30, 2017 , the maximum potential amount of future payments required under the guaranteed leases was $80 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee to the extent of the sale proceeds. As of June 30, 2017 , AEP’s boat and barge lease guarantee liability was $12 million , of which $2 million was recorded in Other Current Liabilities and $10 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. 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, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants 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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of June 30, 2017 , I&M’s accrual for all of these sites is $4 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 sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,278 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). 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 generation 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. Westinghouse Electric Company Bankruptcy Filing (Applies to AEP and I&M) In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, not cease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company can successfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuel fabrication, and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. I&M is evaluating how this reorganization affects these contracts. Westinghouse has stated that it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process for Cook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcy proceedings to avoid any interruptions to that service. In the unlikely event Westinghouse rejects I&M’s contracts, or is unable to reorganize or sell its profitable businesses in the bankruptcy, Cook Plant’s operations would be significantly impacted and potentially shut down temporarily as I&M seeks other vendors for these services. OPERATIONAL CONTINGENCIES Rockport Plant Litigation (Applies to AEP and 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 plaintiffs further allege that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Several claims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filed an amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015, AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state a claim. In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach of contract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim for indemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed to exercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice of voluntary dismissal of all remaining claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court of Appeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate to protect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&M breached the covenant of good faith and fair dealing. In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissed certain of plaintiffs’ claims for breach of contract. The U.S. Court of Appeals for the Sixth Circuit determined that the district court erred in holding that the modification to the consent decree was permitted under the terms of the lease agreement and remanded the case to the district court to enter summary judgment in plaintiffs’ favor consistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit, which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reverses the district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion for partial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment also affirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contract claims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners. Given that the district court dismissed plaintiffs’ claims seeking compensatory relief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages, management is unable to determine a range of potential losses that are reasonably possible of occurring. In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio seeking to modify the consent decree to eliminate the obligation to install future controls at Rockport Unit 2 if AEP does not acquire ownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree. Natural Gas Markets Lawsuits (Applies to AEP) In 2002, a lawsuit was commenced 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 state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was 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 United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three were class actions and one was a single plaintiff case. In February 2017, a settlement was reached in the single plaintiff case. A settlement was also reached in the three class actions and the district court issued final approval of the settlement in June 2017. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and heard oral argument in March 2017. In June 2017, the West Virginia Supreme Court reversed the WVMLP decision and dismissed the claims of the twelve non-working direct claim plaintiffs. Management will continue to defend against the remaining claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring. |
Impairment, Disposition and Ass
Impairment, Disposition and Assets and Liabilities Held for Sale | 6 Months Ended |
Jun. 30, 2017 | |
Impairment, Disposition and Assets and Liabilities Held for Sale | IMPAIRMENT, DISPOSITION, AND ASSETS AND LIABILITIES HELD FOR SALE The disclosures in this note apply to AEP only. IMPAIRMENT Merchant Generating Assets (Generation & Marketing Segment) In September 2016, due to AEP’s ongoing evaluation of strategic alternatives for its merchant generation assets, declining forecasts of future energy and capacity prices, and a decreasing likelihood of cost recovery through regulatory proceedings or legislation in the state of Ohio providing for the recovery of AEP’s existing Ohio merchant generation assets, AEP performed an impairment analysis at the unit level on the remaining merchant generation assets in accordance with accounting guidance for impairments of long-lived assets. Through the second quarter of 2017, AEP recorded an additional pretax impairment of $4 million in Asset Impairments and Other Related Charges on AEP’s statements of income related to the Merchant Coal-fired Generation Assets. In addition, AEP recorded a $9 million pretax impairment as Asset Impairments and Other Related Charges on AEP’s statements of income related to the sale of Zimmer Plant. The sale is further discussed in the “Disposition” section of this note. DISPOSITION Zimmer Plant (Generation & Marketing Segment) In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to a nonaffiliated party. The transaction closed in the second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition. The Income before Income Tax Expense and Equity Earnings of Zimmer Plant was immaterial for the three and six months ended June 30, 2017 and 2016. Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby Plants as well as AEGCo’s Lawrenceburg Plant totaling 5,329 MWs of competitive generation assets to a nonaffiliated party. The sale closed in January 2017 for $2.2 billion , which was recorded in Investing Activities on the statement of cash flows. The net proceeds from the transaction were $1.2 billion in cash after taxes, repayment of debt associated with these assets including a make whole payment related to the debt, payment of a coal contract associated with one of the plants and transaction fees. The sale resulted in a pretax gain of $226 million that was recorded in Gain on Sale of Merchant Generation Assets on AEP’s statement of income. ASSETS AND LIABILITIES HELD FOR SALE Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In the third quarter of 2016, management determined Gavin, Waterford, Darby and Lawrenceburg Plants met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income before Income Tax Expense and Equity Earnings of the four plants was approximately $81 million for the three months ended June 30, 2016 and $42 million (excluding the $226 million pretax gain) and $196 million for the six months ended June 30, 2017 and 2016 , respectively. December 31, 2016 Assets: Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 |
Benefit Plans
Benefit Plans | 6 Months Ended |
Jun. 30, 2017 | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Appalachian Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Indiana Michigan Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Ohio Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Public Service Co Of Oklahoma [Member] | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Southwestern Electric Power Co [Member] | |
Benefit Plans | BENEFIT PLANS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans 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 for the plans: AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Business Segments
Business Segments | 6 Months Ended |
Jun. 30, 2017 | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
AEP Transmission Co [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Appalachian Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Indiana Michigan Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Ohio Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Public Service Co Of Oklahoma [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Southwestern Electric Power Co [Member] | |
Business Segments | BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its 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. AEP’s 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEPTCo. These investments have FERC-approved returns on equity. • Development, construction and operation of transmission facilities through investments in AEP’s transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. The tables below present AEP’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments (Applies to APCo, I&M, OPCo, PSO and SWEPCo) The Registrant Subsidiaries, besides AEPTCo, each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. Other activities are insignificant. 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. AEPTCo’s Reportable Segments AEPTCo Parent is the holding company of seven FERC-regulated transmission-only electric utilities (State Transcos). The seven State Transcos have been identified as operating segments of AEPTCo under the accounting guidance for “Segment Reporting”. The State Transcos business consists of developing, constructing and operating transmission facilities at the request of the regional transmission organizations in which they operate and in replacing and upgrading facilities, assets and components of the existing AEP transmission system as needed to maintain reliability standards and providing service to AEP’s wholesale and retail customers. The State Transcos are regulated for rate-making purposes exclusively by FERC and earn revenues through tariff rates charged for the use of their electric transmission systems. AEPTCo’s Chief Operating Decision Maker (CODM) makes operating decisions, allocates resources to and assesses performance based on these operating segments. The seven State Transco operating segments all have similar economic characteristics and meet all of the criteria under the accounting guidance for “Segment Reporting” to be aggregated into one operating segment. As a result, AEPTCo has one reportable segment. The remainder of AEPTCo’s activity is presented in AEPTCo Parent. While not considered a reportable segment, AEPTCo Parent represents the activity of the holding company which primarily relates to debt financing activity and general corporate activities. The tables below present AEPTCo’s reportable segment income statement information for the three and six months ended June 30, 2017 and 2016 and reportable segment balance sheet information as of June 30, 2017 and December 31, 2016 . These amounts include certain estimates and allocations where necessary. State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Derivatives and Hedging
Derivatives and Hedging | 6 Months Ended |
Jun. 30, 2017 | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Appalachian Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Indiana Michigan Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Ohio Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Public Service Co Of Oklahoma [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Southwestern Electric Power Co [Member] | |
Derivatives and Hedging | DERIVATIVES AND HEDGING The disclosures in this note apply to all Registrants unless indicated otherwise. For the periods presented, AEPTCo did not have any Derivative and Hedging activity. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The Registrants 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: June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the 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 statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. The following table shows the results of hedging gains (losses): Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) During the three and six months ended June 30, 2017 and 2016 , 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 that is attributable to a particular risk), the Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding power derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. During the three and six months ended June 30, 2017 and 2016 , AEP applied cash flow hedging to outstanding interest rate derivatives. During the three and six months ended June 30, 2017 and 2016 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three and six months ended June 30, 2017 and 2016 , the Registrants did not apply cash flow hedging to any outstanding foreign currency derivatives. During the three and six months ended June 30, 2017 and 2016 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of June 30, 2017 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 126 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) 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 Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. 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 that the exposure has been reduced by cash collateral posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering contractual netting arrangements: June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Fair Value Measurements
Fair Value Measurements | 6 Months Ended |
Jun. 30, 2017 | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
AEP Transmission Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Appalachian Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Indiana Michigan Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Ohio Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Public Service Co Of Oklahoma [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Southwestern Electric Power Co [Member] | |
Fair Value Measurements | FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants except AEPTCo unless indicated otherwise. 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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Fair Value Measurements of Long-term Debt (Applies to all Registrants) The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. The following is a summary of Other Temporary Investments: June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. The following table provides the activity for fixed income and equity securities within Other Temporary Investments: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2017 and 2016 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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 following is a summary of nuclear trust fund investments: June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) The following table provides the securities activity within the decommissioning and SNF trusts: Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 The base cost of fixed income securities was $1 billion and $938 million as of June 30, 2017 and December 31, 2016 , respectively. The base cost of equity securities was $578 million and $592 million as of June 30, 2017 and December 31, 2016 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2017 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2017 and 2016 . 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 June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of June 30, 2017 and December 31, 2016 : Sensitivity of Fair Value Measurements Significant |
Income Taxes
Income Taxes | 6 Months Ended |
Jun. 30, 2017 | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
AEP Transmission Co [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Appalachian Power Co [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Indiana Michigan Power Co [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Ohio Power Co [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Public Service Co Of Oklahoma [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Southwestern Electric Power Co [Member] | |
Income Taxes | INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Effective Tax Rates (ETR) The interim ETR for AEP’s operating companies reflect the estimated annual ETR for 2017 and 2016, adjusted for tax expense associated with certain discrete items. The interim ETR differs from the federal statutory tax rate of 35% primarily due to tax adjustments, state income taxes and other book/tax differences which are accounted for on a flow-through basis. The ETR from continuing operations for each of the Registrants are included in the following table. Significant variances in the ETR are described below. Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % AEP Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of a $56 million unrealized capital loss valuation allowance in the second quarter of 2016. The reversal of the unrealized capital loss valuation allowance was the result of AEP effectively settling a 2011 audit issue with the IRS. This increase in the ETR was partially offset by a decrease in pretax book income. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the reversal of the $56 million unrealized capital loss valuation allowance in the second quarter of 2016 described above and an increase in state income taxes resulting primarily from the sale of certain merchant generation assets in the first quarter of 2017 and an increase in pretax book income. I&M Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The decrease in the ETR is primarily due to a decrease in pretax book income. This decrease in the ETR was partially offset by changes in other book/tax differences which are accounted for on a flow-through basis. PSO Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of favorable federal and state income tax adjustments in 2016. SWEPCo Three Months Ended June 30, 2017 Compared to Three Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Six Months Ended June 30, 2017 Compared to Six Months Ended June 30, 2016 The increase in the ETR is primarily due to the recording of net favorable federal and state income tax adjustments in 2016 and changes in other book/tax differences which are accounted for on a flow-through basis. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits are uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants 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. AEP and subsidiaries file income tax returns in various state, local or foreign jurisdictions. These taxing authorities routinely examine the tax returns. AEP and 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 Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. State Tax Legislation (Applies to AEP, APCo and I&M) Legislation was passed by the state of Illinois in July 2017 increasing the corporate income tax rate from 5.25% to 7% effective July 1, 2017, with the increased rate applied to the portion of the tax year falling on or after that date. With the inclusion of the 2.5% Illinois Replacement Tax, the total Illinois corporate income tax rate will increase from 7.75% to 9.5% , effective July 1, 2017. The legislation will not materially impact net income, cash flows or financial condition. |
Financing Activities
Financing Activities | 6 Months Ended |
Jun. 30, 2017 | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
AEP Transmission Co [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Appalachian Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Indiana Michigan Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Ohio Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Public Service Co Of Oklahoma [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Southwestern Electric Power Co [Member] | |
Financing Activities | FINANCING ACTIVITIES The disclosures in this note apply to all Registrants, unless indicated otherwise. Long-term Debt Outstanding (Applies to AEP) The following table details long-term debt outstanding: Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. Long-term Debt Activity Long-term debt and other securities issued, retired and principal payments made during the first six months of 2017 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 In July 2017, I&M retired $5 million of Notes Payable related to DCC Fuel. In July 2017, OPCo retired $24 million of Securitization Bonds. In July 2017, AEP Texas retired $71 million of Securitization Bonds. As of June 30, 2017 , trustees held, on behalf of AEP, $728 million of their reacquired Pollution Control Bonds. Of this total, $104 million , $50 million and $345 million related to APCo, I&M and OPCo, respectively. Debt Covenants (Applies to AEP and AEPTCo) Covenants in AEPTCo’s note purchase agreements and indenture also limit the amount of contractually-defined priority debt (which includes a further sub-limit of $50 million of secured debt) to 10% of consolidated tangible net assets. The method for calculating the consolidated tangible net assets is contractually defined in the note purchase agreements. Dividend Restrictions Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility 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 subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of June 30, 2017 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP 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. Corporate Borrowing Program - AEP System (Applies to Registrant Subsidiaries) 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 certain AEP 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 June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries’ balance sheets. The Utility Money Pool participants’ money pool activity and their corresponding authorized borrowing limits for the six months ended June 30, 2017 are described in the following table: Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. The activity in the above table does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the six months ended June 30, 2017 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 AEP has a direct financing relationship with AEPTCo to meet their short-term borrowing needs. The amounts of outstanding loans to (borrowings from) AEP as of June 30, 2017 and December 31, 2016 are included in Advances to Affiliates and Advances from Affiliates, respectively, on AEPTCo’s balance sheets. AEPTCo’s direct borrowing and lending activity with AEP for the six months ended June 30, 2017 is described in the following table: Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool 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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % AEPTCo’s maximum, minimum and average interest rates for funds either borrowed from or loaned to AEP are summarized in the following table: Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % Short-term Debt (Applies to AEP and SWEPCo) Outstanding short-term debt was as follows: June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 5 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) 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. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables and expires in June 2019 . Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries, except AEPTCo) Under this 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’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Significant Accounting Matters
Significant Accounting Matters (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
Earnings Per Share | Earnings Per Share (EPS) (Applies to AEP) Basic EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. |
AEP Transmission 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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
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. Net income for the three and six months ended June 30, 2017 is not necessarily indicative of results that may be expected for the year ending December 31, 2017 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included in the Registrant’s (except AEPTCo) Annual Reports on Form 10-K as filed with the SEC on February 27, 2017 . AEPTCo should be read in conjunction with the audited 2016 financial statements and notes thereto, which are included on Form S-4 as filed with the SEC on April 5, 2017. |
Derivatives and Hedging (Polici
Derivatives and Hedging (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
Derivatives and Hedging | Accounting for Fair Value Hedging Strategies (Applies to AEP) 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. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and 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 statements of income. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.” Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Fair Value Hedging Strategies (Applies to AEP) Parent 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 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 may be designated as fair value hedges. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. |
Appalachian Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.” The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. |
Indiana Michigan Power Co [Member] | |
Derivatives and Hedging | The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of 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 that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.” OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. |
Ohio Power Co [Member] | |
Derivatives and Hedging | 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.” Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. |
Public Service Co Of Oklahoma [Member] | |
Derivatives and Hedging | Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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.” The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. |
Southwestern Electric Power Co [Member] | |
Derivatives and Hedging | OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. AEP Energy Partners, LLC is agent for and transacts on behalf of other AEP subsidiaries. The Registrants are exposed to certain market risks as major power producers and participants in the electricity, capacity, natural gas, coal and emission allowance markets. These risks include commodity price risks which may be subject to capacity risk, interest rate risk, credit risk and foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. 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 which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants 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. The Registrants utilize power, capacity, 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. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Credit Risk Management mitigates credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses 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. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. Some master agreements include margining, which requires a counterparty to post cash or letters of credit in the event exposure exceeds the established threshold. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a default including a failure or inability to post collateral when required. Collateral Triggering Events Credit Downgrade Triggers (Applies to AEP, APCo, I&M, PSO and SWEPCo) 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, additional amounts of collateral are required if certain credit ratings decline below a specified rating threshold. 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. AEP, APCo, I&M, PSO and SWEPCo have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses 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 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 Registrants 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 balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. 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 purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants 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, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants 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 balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants 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 Registrants 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 Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Depreciation and Amortization expense on the statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. |
Fair Value Measurements (Polici
Fair Value Measurements (Policies) | 6 Months Ended |
Jun. 30, 2017 | |
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 established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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. |
Fair Value Assets and Liabilities Measured on Recurring Basis | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
AEP Transmission Co [Member] | |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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. |
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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 (Applies to AEP and I&M) 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, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. 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 these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities 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 debt 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 debt and equity investments held in these trusts and generally intends to sell debt 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. |
Fair Value Assets and Liabilities Measured on Recurring Basis | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
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, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. AEPSC'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) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s 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 Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the 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, cash and cash equivalents, other temporary investments and restricted cash for securitized funding 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 equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. |
Fair Values of Long-term Debt | Fair Value Measurements of Long-term Debt (Applies to all Registrants) 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 | Fair Value Measurements of Financial Assets and Liabilities The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. |
Significant Accounting Matter24
Significant Accounting Matters (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Basic and Diluted EPS Calculations | Three Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 376.2 $ 506.4 Less: Net Income Attributable to Noncontrolling Interests 1.2 1.8 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 375.0 $ 504.6 Weighted Average Number of Basic Shares Outstanding 491.8 $ 0.76 491.5 $ 1.03 Weighted Average Dilutive Effect of Stock-Based Awards 0.8 — 0.1 — Weighted Average Number of Diluted Shares Outstanding 492.6 $ 0.76 491.6 $ 1.03 Six Months Ended June 30, 2017 2016 (in millions, except per share data) $/share $/share Income from Continuing Operations $ 970.4 $ 1,009.5 Less: Net Income Attributable to Noncontrolling Interests 3.2 3.7 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 967.2 $ 1,005.8 Weighted Average Number of Basic Shares Outstanding 491.8 $ 1.97 491.3 $ 2.05 Weighted Average Dilutive Effect of Stock-Based Awards 0.5 (0.01 ) 0.2 — Weighted Average Number of Diluted Shares Outstanding 492.3 $ 1.96 491.5 $ 2.05 |
Supplementary Information [Text Block] | Six Months Ended June 30, Cash Flow Information 2017 2016 (in millions) Cash Paid (Received) for: Interest, Net of Capitalized Amounts $ 442.3 $ 425.4 Income Taxes (21.2 ) 26.2 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 23.6 52.7 Construction Expenditures Included in Current Liabilities as of June 30, 597.9 554.2 Construction Expenditures Included in Noncurrent Liabilities as of June 30, 71.8 — Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30, 26.0 41.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 2.4 — |
Comprehensive Income (Tables)
Comprehensive Income (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Changes in Accumulated Other Comprehensive Income by Component | AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Pension Total (in millions) Balance in AOCI as of March 31, 2017 $ (39.6 ) $ (15.3 ) $ 9.6 $ (125.7 ) $ (171.0 ) Change in Fair Value Recognized in AOCI (1.8 ) 4.7 0.6 — 3.5 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues — — — — — Purchased Electricity for Resale 8.3 — — — 8.3 Interest Expense — 0.3 — — 0.3 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.3 5.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 8.3 0.3 — 0.4 9.0 Income Tax (Expense) Credit 2.9 0.1 — 0.1 3.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 5.4 0.2 — 0.3 5.9 Net Current Period Other Comprehensive Income 3.6 4.9 0.6 0.3 9.4 Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (16.9 ) $ 7.7 $ (111.7 ) $ (133.8 ) Change in Fair Value Recognized in AOCI 17.1 — 0.6 — 17.7 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (6.7 ) — — — (6.7 ) Purchased Electricity for Resale 3.2 — — — 3.2 Interest Expense — 0.6 — — 0.6 Amortization of Prior Service Cost (Credit) — — — (4.9 ) (4.9 ) Amortization of Actuarial (Gains)/Losses — — — 5.1 5.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (3.5 ) 0.6 — 0.2 (2.7 ) Income Tax (Expense) Credit (1.2 ) 0.2 — 0.1 (0.9 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (2.3 ) 0.4 — 0.1 (1.8 ) Net Current Period Other Comprehensive Income 14.8 0.4 0.6 0.1 15.9 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ (125.9 ) $ (156.3 ) Change in Fair Value Recognized in AOCI (23.6 ) 4.7 1.8 — (17.1 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (4.7 ) — — — (4.7 ) Purchased Electricity for Resale 21.1 — — — 21.1 Interest Expense — 0.8 — — 0.8 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.6 10.6 Reclassifications from AOCI, before Income Tax (Expense) Credit 16.4 0.8 — 0.8 18.0 Income Tax (Expense) Credit 5.7 0.2 — 0.3 6.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10.7 0.6 — 0.5 11.8 Net Current Period Other Comprehensive Income (Loss) (12.9 ) 5.3 1.8 0.5 (5.3 ) Balance in AOCI as of June 30, 2017 $ (36.0 ) $ (10.4 ) $ 10.2 $ (125.4 ) $ (161.6 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Commodity Interest Rate Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ (111.8 ) $ (127.1 ) Change in Fair Value Recognized in AOCI 9.0 — 1.2 — 10.2 Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (15.3 ) — — — (15.3 ) Purchased Electricity for Resale 12.4 — — — 12.4 Interest Expense — 1.1 — — 1.1 Amortization of Prior Service Cost (Credit) — — — (9.8 ) (9.8 ) Amortization of Actuarial (Gains)/Losses — — — 10.2 10.2 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.9 ) 1.1 — 0.4 (1.4 ) Income Tax (Expense) Credit (1.0 ) 0.4 — 0.2 (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.9 ) 0.7 — 0.2 (1.0 ) Net Current Period Other Comprehensive Income 7.1 0.7 1.2 0.2 9.2 Balance in AOCI as of June 30, 2016 $ 1.9 $ (16.5 ) $ 8.3 $ (111.6 ) $ (117.9 ) |
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 June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ 2.7 $ (11.6 ) $ (8.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.3 ) (1.3 ) Amortization of Actuarial (Gains)/Losses — 0.9 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.4 ) (0.7 ) Income Tax (Expense) Credit (0.1 ) (0.1 ) (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.3 ) (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ 3.4 $ (6.7 ) $ (3.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) — (0.3 ) Amortization of Prior Service Cost (Credit) — (1.4 ) (1.4 ) Amortization of Actuarial (Gains)/Losses — 0.8 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) (0.6 ) (0.9 ) Income Tax (Expense) Credit (0.1 ) (0.2 ) (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Net Current Period Other Comprehensive Loss (0.2 ) (0.4 ) (0.6 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ 2.9 $ (11.3 ) $ (8.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.7 1.7 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (0.9 ) (1.5 ) Income Tax (Expense) Credit (0.2 ) (0.3 ) (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.6 ) (1.0 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.6 ) (1.0 ) Balance in AOCI as of June 30, 2017 $ 2.5 $ (11.9 ) $ (9.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ 3.6 $ (6.4 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) — (0.6 ) Amortization of Prior Service Cost (Credit) — (2.6 ) (2.6 ) Amortization of Actuarial (Gains)/Losses — 1.5 1.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) (1.1 ) (1.7 ) Income Tax (Expense) Credit (0.2 ) (0.4 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) (0.7 ) (1.1 ) Net Current Period Other Comprehensive Loss (0.4 ) (0.7 ) (1.1 ) Balance in AOCI as of June 30, 2016 $ 3.2 $ (7.1 ) $ (3.9 ) |
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 June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (11.7 ) $ (4.2 ) $ (15.9 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.1 — 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 — 0.4 Net Current Period Other Comprehensive Income 0.4 — 0.4 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (12.9 ) $ (3.4 ) $ (16.3 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.5 — 0.5 Amortization of Prior Service Cost (Credit) — (0.2 ) (0.2 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.5 — 0.5 Income Tax (Expense) Credit 0.2 — 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.3 — 0.3 Net Current Period Other Comprehensive Income 0.3 — 0.3 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (12.0 ) $ (4.2 ) $ (16.2 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2017 $ (11.3 ) $ (4.2 ) $ (15.5 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (13.3 ) $ (3.4 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.0 — 1.0 Amortization of Prior Service Cost (Credit) — (0.4 ) (0.4 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.0 — 1.0 Income Tax (Expense) Credit 0.3 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 — 0.7 Net Current Period Other Comprehensive Income 0.7 — 0.7 Balance in AOCI as of June 30, 2016 $ (12.6 ) $ (3.4 ) $ (16.0 ) |
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 June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 2.8 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.4 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.4 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.3 ) Net Current Period Other Comprehensive Loss (0.3 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 3.9 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.8 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.8 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.5 ) Net Current Period Other Comprehensive Loss (0.5 ) Balance in AOCI as of June 30, 2017 $ 2.5 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.3 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1.1 ) Income Tax (Expense) Credit (0.3 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.8 ) Net Current Period Other Comprehensive Loss (0.8 ) Balance in AOCI as of June 30, 2016 $ 3.5 |
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 June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2017 $ 3.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of March 31, 2016 $ 4.0 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.3 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.3 ) Income Tax (Expense) Credit (0.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.2 ) Net Current Period Other Comprehensive Loss (0.2 ) Balance in AOCI as of June 30, 2016 $ 3.8 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2016 $ 3.4 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2017 $ 3.0 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate (in millions) Balance in AOCI as of December 31, 2015 $ 4.2 Change in Fair Value Recognized in AOCI — Amount of (Gain) Loss Reclassified from AOCI Interest Expense (0.6 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.6 ) Income Tax (Expense) Credit (0.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.4 ) Net Current Period Other Comprehensive Loss (0.4 ) Balance in AOCI as of June 30, 2016 $ 3.8 |
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 June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2017 $ (6.9 ) $ (2.2 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.4 — 0.4 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.3 0.3 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Net Current Period Other Comprehensive Income (Loss) 0.2 (0.1 ) 0.1 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2016 $ (8.6 ) $ (0.5 ) $ (9.1 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 0.6 — 0.6 Amortization of Prior Service Cost (Credit) — (0.5 ) (0.5 ) Amortization of Actuarial (Gains)/Losses — 0.2 0.2 Reclassifications from AOCI, before Income Tax (Expense) Credit 0.6 (0.3 ) 0.3 Income Tax (Expense) Credit 0.2 (0.1 ) 0.1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Net Current Period Other Comprehensive Income (Loss) 0.4 (0.2 ) 0.2 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2017 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2016 $ (7.4 ) $ (2.0 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.1 — 1.1 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.5 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.1 (0.5 ) 0.6 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.7 (0.3 ) 0.4 Net Current Period Other Comprehensive Income (Loss) 0.7 (0.3 ) 0.4 Balance in AOCI as of June 30, 2017 $ (6.7 ) $ (2.3 ) $ (9.0 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2016 Cash Flow Hedges Interest Rate Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2015 $ (9.1 ) $ (0.3 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense 1.3 — 1.3 Amortization of Prior Service Cost (Credit) — (1.0 ) (1.0 ) Amortization of Actuarial (Gains)/Losses — 0.4 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit 1.3 (0.6 ) 0.7 Income Tax (Expense) Credit 0.4 (0.2 ) 0.2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 0.9 (0.4 ) 0.5 Net Current Period Other Comprehensive Income (Loss) 0.9 (0.4 ) 0.5 Balance in AOCI as of June 30, 2016 $ (8.2 ) $ (0.7 ) $ (8.9 ) |
Rate Matters (Tables)
Rate Matters (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Regulatory Assets Pending Final Regulatory Approval | AEP June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 204.3 $ 159.9 Storm-Related Costs 24.4 25.1 Plant Retirement Costs - Materials and Supplies 9.1 9.1 Ohio Capacity Deferral — 96.7 Other Regulatory Assets Pending Final Regulatory Approval 1.1 1.3 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 41.2 25.9 Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Cook Plant Uprate Project 36.3 36.3 Environmental Control Projects 20.4 24.1 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Other Regulatory Assets Pending Final Regulatory Approval 21.2 21.2 Total Regulatory Assets Pending Final Regulatory Approval (b) $ 421.0 $ 450.1 |
Appalachian Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | APCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 9.1 Regulatory Assets Currently Not Earning a Return Plant Retirement Costs - Asset Retirement Obligation Costs 37.2 29.6 Other Regulatory Assets Pending Final Regulatory Approval 0.6 0.6 Total Regulatory Assets Pending Final Regulatory Approval (a) $ 46.9 $ 39.3 |
Indiana Michigan Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | I&M June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project $ 36.3 $ 36.3 Cook Plant Turbine 14.3 12.8 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 11.5 8.1 Rockport Dry Sorbent Injection System - Indiana 8.3 6.6 Other Regulatory Assets Pending Final Regulatory Approval 1.0 0.9 Total Regulatory Assets Pending Final Regulatory Approval $ 71.4 $ 64.7 |
Ohio Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | OPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Capacity Deferral $ — $ 96.7 Regulatory Assets Currently Not Earning a Return Smart Grid Costs — 4.1 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 100.8 |
Public Service Co Of Oklahoma [Member] | |
Regulatory Assets Pending Final Regulatory Approval | PSO June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant (a) $ 128.9 $ 84.5 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.5 Regulatory Assets Currently Not Earning a Return Storm-Related Costs 35.4 20.0 Environmental Control Projects 20.4 13.1 Other Regulatory Assets Pending Final Regulatory Approval 0.2 — Total Regulatory Assets Pending Final Regulatory Approval $ 185.4 $ 118.1 |
Southwestern Electric Power Co [Member] | |
Regulatory Assets Pending Final Regulatory Approval | SWEPCo June 30, December 31, 2017 2016 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ 75.4 Other Regulatory Assets Pending Final Regulatory Approval 0.5 0.8 Regulatory Assets Currently Not Earning a Return Shipe Road Transmission Project - FERC 3.3 3.1 Asset Retirement Obligation - Arkansas, Louisiana 3.3 2.7 Rate Case Expense - Texas 2.1 1.0 Environmental Control Projects — 11.0 Other Regulatory Assets Pending Final Regulatory Approval 2.1 1.9 Total Regulatory Assets Pending Final Regulatory Approval $ 86.7 $ 95.9 |
Commitments, Guarantees and C27
Commitments, Guarantees and Contingencies (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Appalachian Power Co [Member] | |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Indiana Michigan Power Co [Member] | |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Ohio Power Co [Member] | |
Maximum Future Payments for Letters of Credit Uncommitted Facilities | Company Amount Maturity (in millions) AEP $ 138.7 September 2017 - June 2018 OPCo 0.6 September 2017 |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Public Service Co Of Oklahoma [Member] | |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Southwestern Electric Power Co [Member] | |
Maximum Potential Loss on Master Lease Agreements | Company Maximum Potential Loss (in millions) AEP $ 38.0 APCo 5.6 I&M 3.2 OPCo 5.9 PSO 3.2 SWEPCo 3.6 |
Impairment, Disposition and A28
Impairment, Disposition and Assets and Liabilities Held for Sale (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Assets and Liabilities Held for Sale | December 31, 2016 Assets: Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 |
Benefit Plans (Tables)
Benefit Plans (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Components of Net Periodic Benefit Cost | AEP Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 24.1 $ 21.5 $ 2.8 $ 2.5 Interest Cost 50.8 52.9 14.9 15.2 Expected Return on Plan Assets (71.2 ) (70.0 ) (25.4 ) (26.7 ) Amortization of Prior Service Cost (Credit) 0.2 0.5 (17.2 ) (17.2 ) Amortization of Net Actuarial Loss 20.7 20.9 9.1 7.8 Net Periodic Benefit Cost (Credit) $ 24.6 $ 25.8 $ (15.8 ) $ (18.4 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 48.2 $ 42.9 $ 5.6 $ 5.1 Interest Cost 101.6 105.8 29.7 30.4 Expected Return on Plan Assets (142.4 ) (140.1 ) (50.7 ) (53.5 ) Amortization of Prior Service Cost (Credit) 0.5 1.1 (34.5 ) (34.5 ) Amortization of Net Actuarial Loss 41.4 41.9 18.3 15.7 Net Periodic Benefit Cost (Credit) $ 49.3 $ 51.6 $ (31.6 ) $ (36.8 ) |
Appalachian Power Co [Member] | |
Components of Net Periodic Benefit Cost | APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.4 $ 2.0 $ 0.2 $ 0.3 Interest Cost 6.4 6.8 2.7 2.7 Expected Return on Plan Assets (9.0 ) (8.9 ) (4.1 ) (4.4 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.5 ) (2.5 ) Amortization of Net Actuarial Loss 2.6 2.7 1.5 1.3 Net Periodic Benefit Cost (Credit) $ 2.4 $ 2.7 $ (2.2 ) $ (2.6 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.7 $ 4.0 $ 0.5 $ 0.5 Interest Cost 12.8 13.6 5.3 5.4 Expected Return on Plan Assets (17.9 ) (17.7 ) (8.2 ) (8.7 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (5.0 ) (5.0 ) Amortization of Net Actuarial Loss 5.2 5.4 3.1 2.7 Net Periodic Benefit Cost (Credit) $ 4.9 $ 5.4 $ (4.3 ) $ (5.1 ) |
Indiana Michigan Power Co [Member] | |
Components of Net Periodic Benefit Cost | I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.5 $ 3.1 $ 0.4 $ 0.3 Interest Cost 6.0 6.4 1.8 1.7 Expected Return on Plan Assets (8.7 ) (8.4 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 — (2.4 ) (2.3 ) Amortization of Net Actuarial Loss 2.5 2.4 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 3.4 $ 3.5 $ (2.1 ) $ (2.5 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 7.0 $ 6.1 $ 0.8 $ 0.7 Interest Cost 12.1 12.7 3.5 3.5 Expected Return on Plan Assets (17.3 ) (16.8 ) (6.1 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (4.7 ) (4.7 ) Amortization of Net Actuarial Loss 4.9 4.9 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 6.8 $ 7.0 $ (4.3 ) $ (5.0 ) |
Ohio Power Co [Member] | |
Components of Net Periodic Benefit Cost | OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.9 $ 1.7 $ 0.2 $ 0.2 Interest Cost 4.9 5.1 1.7 1.8 Expected Return on Plan Assets (7.0 ) (7.0 ) (3.0 ) (3.2 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (1.8 ) (1.8 ) Amortization of Net Actuarial Loss 1.9 2.0 1.1 1.0 Net Periodic Benefit Cost (Credit) $ 1.8 $ 1.9 $ (1.8 ) $ (2.0 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.8 $ 3.3 $ 0.4 $ 0.4 Interest Cost 9.7 10.3 3.4 3.5 Expected Return on Plan Assets (14.0 ) (13.9 ) (6.0 ) (6.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.1 (3.5 ) (3.5 ) Amortization of Net Actuarial Loss 3.9 4.0 2.2 1.9 Net Periodic Benefit Cost (Credit) $ 3.5 $ 3.8 $ (3.5 ) $ (4.1 ) |
Public Service Co Of Oklahoma [Member] | |
Components of Net Periodic Benefit Cost | PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 1.6 $ 1.6 $ 0.1 $ 0.1 Interest Cost 2.7 2.8 0.8 0.8 Expected Return on Plan Assets (4.0 ) (3.8 ) (1.4 ) (1.5 ) Amortization of Prior Service Credit — — (1.0 ) (1.0 ) Amortization of Net Actuarial Loss 1.1 1.1 0.5 0.5 Net Periodic Benefit Cost (Credit) $ 1.4 $ 1.7 $ (1.0 ) $ (1.1 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 3.2 $ 3.1 $ 0.3 $ 0.3 Interest Cost 5.4 5.6 1.6 1.6 Expected Return on Plan Assets (7.9 ) (7.7 ) (2.8 ) (3.0 ) Amortization of Prior Service Cost (Credit) — 0.1 (2.1 ) (2.1 ) Amortization of Net Actuarial Loss 2.2 2.2 1.0 0.9 Net Periodic Benefit Cost (Credit) $ 2.9 $ 3.3 $ (2.0 ) $ (2.3 ) |
Southwestern Electric Power Co [Member] | |
Components of Net Periodic Benefit Cost | SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 2.2 $ 2.1 $ 0.2 $ 0.2 Interest Cost 3.0 3.1 0.9 0.9 Expected Return on Plan Assets (4.2 ) (4.2 ) (1.6 ) (1.6 ) Amortization of Prior Service Cost (Credit) — 0.1 (1.3 ) (1.3 ) Amortization of Net Actuarial Loss 1.2 1.2 0.6 0.5 Net Periodic Benefit Cost (Credit) $ 2.2 $ 2.3 $ (1.2 ) $ (1.3 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Service Cost $ 4.4 $ 4.1 $ 0.4 $ 0.4 Interest Cost 6.1 6.2 1.8 1.8 Expected Return on Plan Assets (8.4 ) (8.3 ) (3.2 ) (3.3 ) Amortization of Prior Service Cost (Credit) — 0.2 (2.6 ) (2.6 ) Amortization of Net Actuarial Loss 2.4 2.4 1.2 1.0 Net Periodic Benefit Cost (Credit) $ 4.5 $ 4.6 $ (2.4 ) $ (2.7 ) |
Business Segments (Tables)
Business Segments (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Segment Reporting Information [Line Items] | |
Reportable Segment Information | Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 2,095.7 $ 1,026.6 $ 53.0 $ 386.5 $ 14.7 $ — $ 3,576.5 Other Operating Segments 24.8 26.9 194.3 24.1 14.2 (284.3 ) — Total Revenues $ 2,120.5 $ 1,053.5 $ 247.3 $ 410.6 $ 28.9 $ (284.3 ) $ 3,576.5 Income (Loss) from Continuing Operations $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 121.4 $ 111.2 $ 129.0 $ 26.4 $ (11.8 ) $ — $ 376.2 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,108.2 $ 1,076.2 $ 41.3 $ 655.3 $ 11.9 $ — $ 3,892.9 Other Operating Segments 17.7 19.9 120.4 28.5 18.0 (204.5 ) — Total Revenues $ 2,125.9 $ 1,096.1 $ 161.7 $ 683.8 $ 29.9 $ (204.5 ) $ 3,892.9 Income from Continuing Operations $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 26.3 $ — $ 506.4 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 210.5 $ 124.6 $ 95.3 $ 49.7 $ 23.8 $ — $ 503.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 4,365.5 $ 2,093.0 $ 80.7 $ 945.3 $ 25.3 $ — $ 7,509.8 Other Operating Segments 45.4 46.9 322.7 56.7 30.1 (501.8 ) — Total Revenues $ 4,410.9 $ 2,139.9 $ 403.4 $ 1,002.0 $ 55.4 $ (501.8 ) $ 7,509.8 Income (Loss) from Continuing Operations $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Income from Discontinued Operations, Net of Tax — — — — — — — Net Income (Loss) $ 341.9 $ 230.3 $ 201.8 $ 212.6 $ (16.2 ) $ — $ 970.4 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 4,326.3 $ 2,153.5 $ 70.6 $ 1,369.2 $ 18.2 $ — $ 7,937.8 Other Operating Segments 45.2 39.4 179.7 62.6 36.1 (363.0 ) — Total Revenues $ 4,371.5 $ 2,192.9 $ 250.3 $ 1,431.8 $ 54.3 $ (363.0 ) $ 7,937.8 Income from Continuing Operations $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 27.8 $ — $ 1,009.5 Loss from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income $ 489.2 $ 232.1 $ 140.0 $ 120.4 $ 25.3 $ — $ 1,007.0 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) June 30, 2017 Total Property, Plant and Equipment $ 42,313.2 $ 15,292.0 $ 6,012.1 $ 518.4 $ 365.6 $ (366.5 ) (b) $ 64,134.8 Accumulated Depreciation and Amortization 12,880.0 3,737.9 137.0 145.1 194.0 (186.4 ) (b) 16,907.6 Total Property Plant and Equipment - Net $ 29,433.2 $ 11,554.1 $ 5,875.1 $ 373.3 $ 171.6 $ (180.1 ) (b) $ 47,227.2 Total Assets $ 37,914.1 $ 15,092.4 $ 7,024.9 $ 1,905.7 $ 21,147.9 $ (20,345.9 ) (b) (c) $ 62,739.1 Long-term Debt Due Within One Year: Non-Affiliated $ 1,449.6 $ 756.9 $ — $ — $ 548.5 $ — $ 2,755.0 Long-term Debt: Affiliated 40.0 — — 32.2 — (72.2 ) — Non-Affiliated 10,347.5 4,088.0 2,063.5 — 297.9 — 16,796.9 Total Long-term Debt $ 11,837.1 $ 4,844.9 $ 2,063.5 $ 32.2 $ 846.4 $ (72.2 ) $ 19,551.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2016 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (b) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (b) 16,397.3 Total Property Plant and Equipment - Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (b) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (b) (c) $ 63,467.7 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes eliminations due to an intercompany capital lease. (c) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. |
AEP Transmission Co [Member] | |
Segment Reporting Information [Line Items] | |
Reportable Segment Information | State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2017 Revenues from: External Customers $ 44.0 $ — $ — $ 44.0 Sales to AEP Affiliates 185.5 — (0.1 ) 185.4 Total Revenues $ 229.5 $ — $ (0.1 ) $ 229.4 Interest Income - Affiliated $ — $ 19.4 $ (19.3 ) (a) $ 0.1 Interest Expense 15.9 19.1 (19.3 ) (a) 15.7 Income Tax Expense 55.7 0.1 — 55.8 Equity Earnings in State Transcos — 107.4 (107.4 ) (b) — Net Income (Loss) $ 107.4 $ 107.4 $ (107.4 ) (b) $ 107.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Three Months Ended June 30, 2016 Revenues from: External Customers $ 34.1 $ — $ — $ 34.1 Sales to AEP Affiliates 119.0 — — 119.0 Total Revenues $ 153.1 $ — $ — $ 153.1 Interest Income - Affiliated $ — $ 13.9 $ (13.8 ) (a) $ 0.1 Interest Expense 10.5 13.9 (13.9 ) (a) 10.5 Income Tax Expense 37.0 — — 37.0 Equity Earnings in State Transcos — 74.8 (74.8 ) (b) — Net Income (Loss) $ 74.8 $ 74.8 $ (74.8 ) (b) $ 74.8 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2017 Revenues from: External Customers $ 63.3 $ — $ — $ 63.3 Sales to AEP Affiliates 318.9 — (0.1 ) 318.8 Total Revenues $ 382.2 $ — $ (0.1 ) $ 382.1 Interest Income - Affiliated $ 0.1 $ 38.5 $ (38.3 ) (a) $ 0.3 Interest Expense 31.7 38.3 (38.3 ) (a) 31.7 Income Tax Expense 84.1 0.2 — 84.3 Equity Earnings in State Transcos — 164.2 (164.2 ) (b) — Net Income (Loss) $ 164.2 $ 164.4 $ (164.2 ) (b) $ 164.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo Consolidated (in millions) Six Months Ended June 30, 2016 Revenues from: External Customers $ 56.1 $ — $ — $ 56.1 Sales to AEP Affiliates 176.6 — — 176.6 Total Revenues $ 232.7 $ — $ — $ 232.7 Interest Income - Affiliated $ — $ 27.8 $ (27.7 ) (a) $ 0.1 Interest Expense 21.3 27.7 (27.7 ) (a) 21.3 Income Tax Expense 47.5 — — 47.5 Equity Earnings in State Transcos — 100.6 (100.6 ) (b) — Net Income (Loss) $ 100.6 $ 100.6 $ (100.6 ) (b) $ 100.6 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) June 30, 2017 Total Transmission Property $ 5,690.3 $ — $ — $ 5,690.3 Accumulated Depreciation and Amortization 133.1 — — 133.1 Total Transmission Property – Net $ 5,557.2 $ — $ — $ 5,557.2 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,924.5 $ 4,282.5 $ (4,263.4 ) (d) $ 5,943.6 Total Long-term Debt $ 1,931.4 $ 1,950.0 $ (1,950.0 ) (c) $ 1,931.4 State Transcos AEPTCo Parent Reconciling Adjustments AEPTCo (in millions) December 31, 2016 Total Transmission Property $ 5,054.2 $ — $ — $ 5,054.2 Accumulated Depreciation and Amortization 99.6 — — 99.6 Total Transmission Property – Net $ 4,954.6 $ — $ — $ 4,954.6 Notes Receivable - Affiliated $ — $ 1,950.0 $ (1,950.0 ) (c) $ — Total Assets $ 5,337.5 $ 3,947.8 $ (3,935.5 ) (d) $ 5,349.8 Total Long-term Debt $ 1,932.0 $ 1,950.0 $ (1,950.0 ) (c) $ 1,932.0 (a) Elimination of intercompany interest income/interest expense on affiliated debt arrangement. (b) Elimination of AEPTCo Parent’s equity earnings in the State Transcos. (c) Elimination of intercompany debt. (d) Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Derivatives and Hedging (Tables
Derivatives and Hedging (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | AEP Fair Value of Derivative Instruments June 30, 2017 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 366.0 $ 8.1 $ 4.8 $ 378.9 $ (208.4 ) $ 170.5 Long-term Risk Management Assets 340.6 4.1 — 344.7 (59.1 ) 285.6 Total Assets 706.6 12.2 4.8 723.6 (267.5 ) 456.1 Current Risk Management Liabilities 260.1 12.1 1.5 273.7 (212.0 ) 61.7 Long-term Risk Management Liabilities 325.6 55.3 — 380.9 (70.3 ) 310.6 Total Liabilities 585.7 67.4 1.5 654.6 (282.3 ) 372.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 120.9 $ (55.2 ) $ 3.3 $ 69.0 $ 14.8 $ 83.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Gain (Loss) on Hedging Instruments | Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Gain (Loss) on Fair Value Hedging Instruments $ 0.4 $ 0.6 $ (0.1 ) $ 4.1 Gain (Loss) on Fair Value Portion of Long-term Debt (0.4 ) (0.6 ) 0.1 (4.1 ) |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on AEP’s Balance Sheets June 30, 2017 December 31, 2016 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 4.0 $ 4.8 $ 11.2 $ — Hedging Liabilities (a) 59.2 — 46.7 — AOCI Gain (Loss) Net of Tax (36.0 ) (10.4 ) (23.1 ) (15.7 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months (2.7 ) (0.7 ) 4.3 (1.0 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. |
Collateral Required Under Various Triggering Events | June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Liabilities Subject to Cross Default Provisions | June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Appalachian Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | APCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 72.3 $ (30.7 ) $ 41.6 Long-term Risk Management Assets 6.6 (6.6 ) — Total Assets 78.9 (37.3 ) 41.6 Current Risk Management Liabilities 29.5 (29.1 ) 0.4 Long-term Risk Management Liabilities 6.6 (6.2 ) 0.4 Total Liabilities 36.1 (35.3 ) 0.8 Total MTM Derivative Contract Net Assets (Liabilities) $ 42.8 $ (2.0 ) $ 40.8 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) |
Collateral Required Under Various Triggering Events | June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Liabilities Subject to Cross Default Provisions | June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Indiana Michigan Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | I&M Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 37.9 $ (22.1 ) $ 15.8 Long-term Risk Management Assets 4.2 (4.2 ) — Total Assets 42.1 (26.3 ) 15.8 Current Risk Management Liabilities 21.1 (20.2 ) 0.9 Long-term Risk Management Liabilities 4.0 (3.8 ) 0.2 Total Liabilities 25.1 (24.0 ) 1.1 Total MTM Derivative Contract Net Assets (Liabilities) $ 17.0 $ (2.3 ) $ 14.7 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) |
Collateral Required Under Various Triggering Events | June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Liabilities Subject to Cross Default Provisions | June 30, 2017 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 millions) AEP $ 247.0 $ 2.3 $ 234.1 APCo — — — I&M — — — December 31, 2016 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 millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — |
Ohio Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | OPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ — $ — $ — Long-term Risk Management Assets — — — Total Assets — — — Current Risk Management Liabilities 7.1 — 7.1 Long-term Risk Management Liabilities 123.5 — 123.5 Total Liabilities 130.6 — 130.6 Total MTM Derivative Contract Net Liabilities $ (130.6 ) $ — $ (130.6 ) Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) |
Public Service Co Of Oklahoma [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | PSO Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 9.9 $ (0.4 ) $ 9.5 Long-term Risk Management Assets — — — Total Assets 9.9 (0.4 ) 9.5 Current Risk Management Liabilities 0.4 (0.4 ) — Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.4 ) — Total MTM Derivative Contract Net Assets $ 9.5 $ — $ 9.5 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) |
Collateral Required Under Various Triggering Events | June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Southwestern Electric Power Co [Member] | |
Notional Volume of Derivative Instruments | Notional Volume of Derivative Instruments June 30, 2017 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 472.7 91.5 54.6 10.7 30.5 36.4 Coal Tons 1.0 — 0.5 — — 0.5 Natural Gas MMBtus 26.6 1.9 1.1 — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.7 0.7 0.9 Interest Rate USD $ 62.0 $ — $ — $ — $ — $ — Interest Rate USD $ 1,000.0 $ — $ — $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — |
Cash Collateral Netting | June 30, 2017 December 31, 2016 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 millions) AEP $ 9.2 $ 24.0 $ 7.9 $ 7.6 APCo 2.1 0.1 0.5 0.7 I&M 2.3 — 0.3 0.4 OPCo — — 0.2 — PSO — — 0.1 — SWEPCo — — 0.1 — |
Fair Value of Derivative Instruments | SWEPCo Fair Value of Derivative Instruments June 30, 2017 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 12.9 $ (0.4 ) $ 12.5 Long-term Risk Management Assets — — — Total Assets 12.9 (0.4 ) 12.5 Current Risk Management Liabilities 0.9 (0.4 ) 0.5 Long-term Risk Management Liabilities — — — Total Liabilities 0.9 (0.4 ) 0.5 Total MTM Derivative Contract Net Assets $ 12.0 $ — $ 12.0 Fair Value of Derivative Instruments December 31, 2016 Risk Management Gross Amounts Offset Net Amounts of Assets/Liabilities Contracts - in the Statement of Presented in the Statement Balance Sheet Location Commodity (a) Financial Position (b) of Financial Position (c) (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (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 June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 0.6 $ — $ — $ — $ — $ — Generation & Marketing Revenues 10.3 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.1 ) 0.5 — — — Purchased Electricity for Resale 1.5 0.5 0.2 — — — Other Operation Expense 0.2 — — — — — Maintenance Expense 0.1 — — — — — Regulatory Assets (a) (3.1 ) 5.7 — (8.6 ) — — Regulatory Liabilities (a) 41.0 13.6 6.4 — 8.7 10.4 Total Gain (Loss) on Risk Management Contracts $ 50.6 $ 19.7 $ 7.1 $ (8.6 ) $ 8.7 $ 10.4 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 21.1 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.0 ) 0.9 — — — Sales to AEP Affiliates — 1.0 1.8 — — — Purchased Electricity for Resale 1.3 0.5 — — — — Other Operation Expense (0.2 ) — — (0.1 ) — (0.1 ) Maintenance Expense (0.4 ) — — (0.1 ) — — Regulatory Assets (a) (14.3 ) (12.6 ) 1.1 (5.6 ) 0.3 2.6 Regulatory Liabilities (a) 17.1 6.4 1.8 — 2.9 6.5 Total Gain (Loss) on Risk Management Contracts $ 24.7 $ (5.7 ) $ 5.6 $ (5.8 ) $ 3.2 $ 9.0 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2017 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utility Revenues $ 6.1 $ — $ — $ — $ — $ — Generation & Marketing Revenues 20.8 — — — — — Electric Generation, Transmission and Distribution Revenues — 0.3 5.7 — — 0.1 Purchased Electricity for Resale 3.9 1.3 0.3 — — — Other Operation Expense 0.4 — — — — — Maintenance Expense 0.3 — — — — — Regulatory Assets (a) (18.0 ) (0.1 ) (0.2 ) (17.2 ) — (0.2 ) Regulatory Liabilities (a) 66.2 24.5 13.2 — 11.1 15.0 Total Gain (Loss) on Risk Management Contracts $ 79.7 $ 26.0 $ 19.0 $ (17.2 ) $ 11.1 $ 14.9 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 0.7 $ — $ — $ — $ — $ — Generation & Marketing Revenues 40.9 — — — — — Electric Generation, Transmission and Distribution Revenues — (1.8 ) 2.5 — — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 3.4 1.9 0.1 — — — Other Operation Expense (0.9 ) (0.1 ) (0.1 ) (0.2 ) (0.1 ) (0.2 ) Maintenance Expense (1.2 ) (0.2 ) (0.1 ) (0.2 ) (0.1 ) (0.1 ) Regulatory Assets (a) (28.4 ) (12.4 ) 1.4 (20.5 ) 0.3 2.7 Regulatory Liabilities (a) 29.3 22.3 5.7 (15.2 ) 2.4 11.0 Total Gain (Loss) on Risk Management Contracts $ 43.8 $ 11.8 $ 15.3 $ (36.1 ) $ 2.5 $ 13.4 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Impact of Cash Flow Hedges on the Condensed Balance Sheet | Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets June 30, 2017 December 31, 2016 Interest Rate Expected to be Expected to be Reclassified to Reclassified to Net Income During Net Income During AOCI Gain (Loss) the Next AOCI Gain (Loss) the Next Company Net of Tax Twelve Months Net of Tax Twelve Months (in millions) APCo $ 2.5 $ 0.7 $ 2.9 $ 0.7 I&M (11.3 ) (1.3 ) (12.0 ) (1.3 ) OPCo 2.5 1.1 3.0 1.1 PSO 3.0 0.8 3.4 0.8 SWEPCo (6.7 ) (1.4 ) (7.4 ) (1.4 ) |
Collateral Required Under Various Triggering Events | June 30, 2017 December 31, 2016 Amount of Collateral Amount of Amount of Collateral Amount of That Would Collateral That Would Collateral Have Been Required Attributable to Have Been Required Attributable to to Post Attributable Other to Post Attributable Other Company to RTOs and ISOs Contracts to RTOs and ISOs Contracts (in millions) AEP $ 38.7 $ 197.3 (a) $ 9.3 $ 280.3 (a) APCo 7.4 — 1.0 — I&M 4.5 — 0.6 — PSO 3.7 3.3 2.1 3.2 SWEPCo 6.2 0.1 2.5 0.1 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Other Temporary Investments | June 30, 2017 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 193.7 $ — $ — $ 193.7 Fixed Income Securities – Mutual Funds (b) 93.5 — (0.7 ) 92.8 Equity Securities – Mutual Funds 14.7 16.4 — 31.1 Total Other Temporary Investments $ 301.9 $ 16.4 $ (0.7 ) $ 317.6 December 31, 2016 Gross Gross Unrealized Unrealized Fair Other Temporary Investments Cost Gains Losses Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 (a) Primarily represents amounts held for the repayment of debt. (b) Primarily short and intermediate maturities which may be sold and do not contain maturity dates. |
Debt and Equity Securities Within Other Temporary Investments | Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments 0.5 0.6 1.0 1.0 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — |
Nuclear Trust Fund Investments | June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 172.4 $ 172.4 Other Temporary Investments Restricted Cash (a) 156.3 1.3 — 36.1 193.7 Fixed Income Securities – Mutual Funds 92.8 — — — 92.8 Equity Securities – Mutual Funds (b) 31.1 — — — 31.1 Total Other Temporary Investments 280.2 1.3 — 36.1 317.6 Risk Management Assets Risk Management Commodity Contracts (c) (d) 1.5 388.7 291.0 (233.9 ) 447.3 Cash Flow Hedges: Commodity Hedges (c) — 9.1 1.1 (6.2 ) 4.0 Interest Rate/Foreign Currency Hedges — 4.8 — — 4.8 Total Risk Management Assets 1.5 402.6 292.1 (240.1 ) 456.1 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities – Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,604.3 $ 1,453.7 $ 292.1 $ (22.0 ) $ 3,328.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 4.3 $ 377.1 $ 178.9 $ (248.7 ) $ 311.6 Cash Flow Hedges: Commodity Hedges (c) — 39.5 25.9 (6.2 ) 59.2 Fair Value Hedges — 1.5 — — 1.5 Total Risk Management Liabilities $ 4.3 $ 418.1 $ 204.8 $ (254.9 ) $ 372.3 AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (f) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs June 30, 2017 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 201.0 $ 200.8 Discounted Cash Flow Forward Market Price (a) $ 10.98 $ 99.44 $ 38.28 Counterparty Credit Risk (b) 19 783 288 FTRs 91.1 4.0 Discounted Cash Flow Forward Market Price (a) (6.70 ) 7.35 0.36 Total $ 292.1 $ 204.8 Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
AEP Transmission Co [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Appalachian Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Fair Value, Assets and Liabilities Measured on Recurring Basis | (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.4 $ — $ — $ 0.1 $ 15.5 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 33.2 41.6 (33.2 ) 41.6 Total Assets $ 15.4 $ 33.2 $ 41.6 $ (33.1 ) $ 57.1 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 31.7 $ 0.3 $ (31.2 ) $ 0.8 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs June 30, 2017 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 40.8 0.2 Discounted Cash Flow Forward Market Price 0.10 7.35 1.23 Total $ 41.6 $ 0.3 Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Indiana Michigan Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Nuclear Trust Fund Investments | June 30, 2017 December 31, 2016 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in millions) Cash and Cash Equivalents $ 19.2 $ — $ — $ 18.7 $ — $ — Fixed Income Securities: United States Government 904.1 33.5 (304.1 ) 785.4 27.1 (5.5 ) Corporate Debt 59.0 3.3 (1.2 ) 60.9 2.3 (1.4 ) State and Local Government 86.7 — (1.2 ) 121.1 0.4 (0.7 ) Subtotal Fixed Income Securities 1,049.8 36.8 (306.5 ) 967.4 29.8 (7.6 ) Equity Securities - Domestic 1,313.0 735.5 (76.1 ) 1,270.1 677.9 (79.6 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,382.0 $ 772.3 $ (382.6 ) $ 2,256.2 $ 707.7 $ (87.2 ) |
Securities Activity Within the Decommissioning and SNF Trusts | Three Months Ended June 30, Six Months Ended June 30, 2017 2016 2017 2016 (in millions) Proceeds from Investment Sales $ 801.2 $ 639.3 $ 1,289.1 $ 1,777.0 Purchases of Investments 811.7 644.8 1,317.2 1,796.4 Gross Realized Gains on Investment Sales 177.0 12.2 188.3 28.0 Gross Realized Losses on Investment Sales 132.1 7.9 140.2 15.7 |
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts | Fair Value of Fixed Income Securities (in millions) Within 1 year $ 243.9 1 year – 5 years 398.9 5 years – 10 years 160.6 After 10 years 246.4 Total $ 1,049.8 |
Fair Value, Assets and Liabilities Measured on Recurring Basis | (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 22.6 $ 17.0 $ (23.8 ) $ 15.8 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9.6 — — 9.6 19.2 Fixed Income Securities: United States Government — 904.1 — — 904.1 Corporate Debt — 59.0 — — 59.0 State and Local Government — 86.7 — — 86.7 Subtotal Fixed Income Securities — 1,049.8 — — 1,049.8 Equity Securities - Domestic (b) 1,313.0 — — — 1,313.0 Total Spent Nuclear Fuel and Decommissioning Trusts 1,322.6 1,049.8 — 9.6 2,382.0 Total Assets $ 1,322.6 $ 1,072.4 $ 17.0 $ (14.2 ) $ 2,397.8 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 21.1 $ 1.5 $ (21.5 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities - Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs June 30, 2017 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.6 $ 0.1 Discounted Cash Flow Forward Market Price $ 17.85 $ 46.97 $ 33.62 FTRs 16.4 1.4 Discounted Cash Flow Forward Market Price 0.01 6.93 0.79 Total $ 17.0 $ 1.5 Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Ohio Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Fair Value, Assets and Liabilities Measured on Recurring Basis | OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.3 $ 27.3 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.1 $ 130.5 $ — $ 130.6 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs June 30, 2017 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 130.5 Discounted Cash Flow Forward Market Price (a) $ 27.17 $ 66.88 $ 43.36 Counterparty Credit Risk (b) 19 302 214 Total $ — $ 130.5 Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Public Service Co Of Oklahoma [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Fair Value, Assets and Liabilities Measured on Recurring Basis | (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ — $ 9.9 $ (0.4 ) $ 9.5 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 0.4 $ (0.4 ) $ — PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs June 30, 2017 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 9.9 $ 0.4 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Southwestern Electric Power Co [Member] | |
Book Values and Fair Values of Long-term Debt | June 30, 2017 December 31, 2016 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 19,551.9 $ 21,857.2 $ 20,391.2 (a) $ 22,211.9 (a) AEPTCo 1,931.4 2,105.2 1,932.0 1,984.3 APCo 3,990.5 4,734.5 4,033.9 4,613.2 I&M 2,691.4 2,937.7 2,471.4 2,661.6 OPCo 1,742.5 2,098.7 1,763.9 2,092.5 PSO 1,286.3 1,451.5 1,286.0 1,419.0 SWEPCo 2,442.7 2,634.8 2,679.1 2,814.3 (a) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million . See the Assets and Liabilities Held for Sale section of Note 6 for additional information. |
Fair Value, Assets and Liabilities Measured on Recurring Basis | SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2017 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ — $ — $ — $ 1.7 $ 1.7 Risk Management Assets Risk Management Commodity Contracts (c) (g) — — 12.9 (0.4 ) 12.5 Total Assets $ — $ — $ 12.9 $ 1.3 $ 14.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.4 $ 0.5 $ (0.4 ) $ 0.5 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 (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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (g) Substantially comprised of power contracts for the Registrant Subsidiaries. |
Changes in Fair Value of Net Trading Derivatives and Other Investments | Three Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of March 31, 2017 $ (18.5 ) $ (5.8 ) $ 2.0 $ (124.6 ) $ 0.4 $ 0.5 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 17.1 12.2 0.6 (0.1 ) 0.8 1.4 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 8.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 12.1 — — — — — Settlements (16.1 ) (6.4 ) (2.7 ) 1.9 (1.3 ) (1.9 ) Transfers into Level 3 (d) (e) 6.2 — — — — — Transfers out of Level 3 (e) (1.1 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 78.9 41.3 15.6 (7.7 ) 9.6 12.4 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Three Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of March 31, 2016 $ 141.3 $ 2.6 $ 3.7 $ (10.9 ) $ 0.6 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 16.0 8.6 3.5 (0.2 ) (0.4 ) 2.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 2.9 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 17.3 — — — — — Settlements (17.5 ) (6.8 ) (4.6 ) 1.7 (0.2 ) (3.5 ) Transfers into Level 3 (d) (e) 8.2 — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (18.9 ) (17.3 ) 0.9 (5.2 ) 1.1 1.5 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 Six Months Ended June 30, 2017 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 32.0 16.9 3.9 (4.3 ) 3.1 6.0 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 25.2 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (5.1 ) — — — — — Settlements (44.3 ) (18.6 ) (6.9 ) 4.1 (3.8 ) (6.8 ) Transfers into Level 3 (d) (e) 10.7 — — — — — Transfers out of Level 3 (e) (9.4 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 75.7 41.6 15.7 (11.3 ) 9.5 12.5 Balance as of June 30, 2017 $ 87.3 $ 41.3 $ 15.5 $ (130.5 ) $ 9.5 $ 12.4 Six Months Ended June 30, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 41.3 25.1 6.7 (1.4 ) (1.0 ) 7.7 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 24.8 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 18.8 — — — — — Settlements (60.0 ) (34.5 ) (9.2 ) 3.1 0.4 (8.4 ) Transfers into Level 3 (d) (e) 8.1 — — — — — Transfers out of Level 3 (e) 10.9 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (41.5 ) (15.3 ) 1.6 (32.2 ) 1.1 1.3 Balance as of June 30, 2016 $ 149.3 $ (12.9 ) $ 3.5 $ (14.6 ) $ 1.1 $ 1.4 (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (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) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. |
Significant Unobservable Inputs for Level 3 | Significant Unobservable Inputs June 30, 2017 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 12.9 $ 0.5 Discounted Cash Flow Forward Market Price $ (6.70 ) $ 0.13 $ (0.67 ) Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) (a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. |
Sensitivity of Fair Value Measurements | Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher) |
Income Taxes Income Taxes (Tabl
Income Taxes Income Taxes (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
AEP Transmission Co [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Appalachian Power Co [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Indiana Michigan Power Co [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Ohio Power Co [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Public Service Co Of Oklahoma [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Southwestern Electric Power Co [Member] | |
Summary of Effective Tax Rate | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEP 34.6 % 24.3 % 36.5 % 28.8 % AEPTCo 34.2 % 33.1 % 33.9 % 32.1 % APCo 36.5 % 35.9 % 36.5 % 36.3 % I&M 27.6 % 32.9 % 29.6 % 28.1 % OPCo 34.9 % 34.1 % 34.9 % 34.5 % PSO 37.6 % 36.2 % 37.6 % 35.5 % SWEPCo 29.7 % 23.6 % 32.4 % 23.7 % |
Financing Activities (Tables)
Financing Activities (Tables) | 6 Months Ended |
Jun. 30, 2017 | |
Long-term Debt | Type of Debt June 30, 2017 December 31, 2016 (in millions) Senior Unsecured Notes $ 14,728.9 $ 14,761.0 (b) Pollution Control Bonds 1,611.1 1,725.1 Notes Payable 259.7 326.9 Securitization Bonds 1,555.8 1,705.0 Spent Nuclear Fuel Obligation (a) 267.1 266.3 Other Long-term Debt 1,129.3 1,606.9 Total Long-term Debt Outstanding 19,551.9 20,391.2 (b) Long-term Debt Due Within One Year 2,755.0 3,013.4 (b) Long-term Debt $ 16,796.9 $ 17,377.8 (b) (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 $310 million and $311 million as of June 30, 2017 and December 31, 2016 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. (b) Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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 | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Short Term Debt | June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (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 Six Months Ended 2017 2016 2017 2016 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 1.17 % 0.63 % 1.09 % 0.61 % Net Uncollectible Accounts Receivable Written Off $ 5.3 $ 4.1 $ 11.2 $ 9.8 |
Customer Accounts Receivable Managed Portfolio | June 30, 2017 December 31, 2016 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 921.7 $ 945.0 Short-term – Securitized Debt of Receivables 519.0 673.0 Delinquent Securitized Accounts Receivable 44.3 42.7 Bad Debt Reserves Related to Securitization 27.7 27.7 Unbilled Receivables Related to Securitization 347.9 322.1 |
AEP Transmission Co [Member] | |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Direct Borrowing Activity | Maximum Maximum Average Average Borrowings from Loans to Authorized Borrowings Loans Borrowings Loans AEP as of AEP as of Short-term from AEP to AEP from AEP to AEP June 30, 2017 June 30, 2017 Borrowing Limit (in millions) $ 1.1 $ 78.9 $ 1.1 $ 34.8 $ 1.1 $ 22.2 $ 75.0 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Maximum Minimum and Average Interest Rates for Funds Borrowed from and Loaned to AEP | Maximum Minimum Maximum Minimum Average Average Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Interest Rate Six Months for Funds for Funds for Funds for Funds for Funds for Funds Ended Borrowed Borrowed Loaned Loaned Borrowed Loaned June 30, from AEP from AEP to AEP to AEP from AEP to AEP 2017 1.44 % 0.92 % 1.44 % 0.92 % 1.18 % 1.21 % 2016 0.84 % 0.69 % 0.84 % 0.69 % 0.75 % 0.75 % |
Appalachian Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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 | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Accounts Receivable and Accrued Unbilled Revenues | Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Indiana Michigan Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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 | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Accounts Receivable and Accrued Unbilled Revenues | Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Ohio Power Co [Member] | |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Accounts Receivable and Accrued Unbilled Revenues | Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Public Service Co Of Oklahoma [Member] | |
Retirements and Principal Payments | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Accounts Receivable and Accrued Unbilled Revenues | Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Southwestern Electric Power Co [Member] | |
Long-term Debt Issuances | Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in millions) (%) APCo Senior Unsecured Notes $ 325.0 3.30 2027 I&M Pollution Control Bonds 25.0 Variable 2019 I&M Pollution Control Bonds 40.0 2.05 2021 I&M Pollution Control Bonds 52.0 Variable 2021 I&M Senior Unsecured Notes 300.0 3.75 2047 SWEPCo Other Long-term Debt 115.0 Variable 2020 Non-Registrant: KPCo Pollution Control Bonds 65.0 2.00 2020 Transource Missouri Other Long-term Debt 7.0 Variable 2018 Transource Energy Other Long-term Debt 132.1 Variable 2020 Total Issuances $ 1,061.1 (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 | Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in millions) (%) APCo Senior Unsecured Notes $ 250.0 5.00 2017 APCo Securitization Bonds 11.5 2.008 2024 APCo Pollution Control Bonds 104.4 Variable 2017 I&M Notes Payable 3.3 Variable 2017 I&M Pollution Control Bonds 25.0 Variable 2017 I&M Notes Payable 14.9 Variable 2019 I&M Notes Payable 15.8 Variable 2019 I&M Notes Payable 15.9 Variable 2020 I&M Pollution Control Bonds 52.0 Variable 2017 I&M Notes Payable 15.7 Variable 2021 I&M Other Long-term Debt 0.7 6.00 2025 I&M Pollution Control Bonds 50.0 Variable 2025 OPCo Securitization Bonds 22.5 0.958 2018 PSO Other Long-term Debt 0.2 3.00 2027 SWEPCo Senior Unsecured Notes 250.0 5.55 2017 SWEPCo Other Long-term Debt 100.0 Variable 2017 SWEPCo Other Long-term Debt 0.1 3.50 2023 SWEPCo Other Long-term Debt 0.1 4.28 2023 SWEPCo Notes Payable 1.6 4.58 2032 Non-Registrant: AEGCo Senior Unsecured Notes 152.7 6.33 2037 AGR Other Long-term Debt 500.0 Variable 2017 KPCo Pollution Control Bonds 65.0 Variable 2017 TCC Securitization Bonds 27.2 0.88 2017 TCC Securitization Bonds 89.9 5.17 2018 Transource Missouri Other Long-term Debt 130.8 Variable 2018 Total Retirements and Principal Payments $ 1,899.3 |
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits | Maximum Average Net Borrowings Maximum Borrowings Average Borrowings from Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2017 Limit (in millions) AEPTCo $ 333.3 $ 52.9 $ 170.7 $ 12.3 $ 246.3 $ 795.0 (a) APCo 231.5 160.7 179.1 36.4 100.9 600.0 I&M 367.4 12.6 258.6 12.6 30.8 500.0 OPCo 243.7 56.2 91.7 27.9 190.5 400.0 PSO 185.2 — 123.6 — 141.4 300.0 SWEPCo 187.5 178.6 132.4 169.5 58.6 350.0 (a) Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |
Nonutility Money Pool Activity | Maximum Average Loans Loans Loans to the Nonutility to the Nonutility to the Nonutility Money Pool as of Money Pool Money Pool June 30, 2017 (in millions) $ 2.0 $ 2.0 $ 2.0 |
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool | Six Months Ended June 30, 2017 2016 Maximum Interest Rate 1.44 % 0.84 % Minimum Interest Rate 0.92 % 0.69 % |
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 Six Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 AEPTCo 1.25 % 0.76 % 0.99 % 0.74 % APCo 1.17 % 0.75 % 1.22 % 0.75 % I&M 1.20 % 0.72 % 1.18 % 0.75 % OPCo 1.31 % 0.79 % 0.98 % 0.74 % PSO 1.23 % 0.76 % — % 0.73 % SWEPCo 1.20 % 0.75 % 0.98 % — % |
Maximum Minimum Average Interest Rates for Funds Borrowed from Loaned to Nonutility Money Pool | Maximum Minimum Average Interest Rate Interest Rate Interest Rate Six Months for Funds Loaned for Funds Loaned for Funds Loaned Ended to the Nonutility to the Nonutility to the Nonutility June 30, Money Pool Money Pool Money Pool 2017 1.44 % — % 1.17 % 2016 0.84 % 0.69 % 0.75 % |
Short Term Debt | June 30, 2017 December 31, 2016 Company Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) AEP Securitized Debt for Receivables (b) $ 519.0 1.09 % $ 673.0 0.70 % AEP Commercial Paper 1,324.0 1.43 % 1,040.0 1.02 % SWEPCo Notes Payable 8.7 2.77 % — — % Total Short-term Debt $ 1,851.7 $ 1,713.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. |
Accounts Receivable and Accrued Unbilled Revenues | Company June 30, 2017 December 31, 2016 (in millions) APCo $ 127.5 $ 142.0 I&M 145.6 136.7 OPCo 322.4 388.3 PSO 136.1 110.4 SWEPCo 163.5 130.9 |
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 1.3 $ 2.0 $ 2.7 $ 3.8 I&M 1.6 1.7 3.1 3.6 OPCo 4.7 7.4 10.4 15.3 PSO 1.7 1.5 3.2 2.9 SWEPCo 1.8 1.7 3.4 3.2 |
Proceeds on Sale of Receivables to AEP Credit | Three Months Ended June 30, Six Months Ended June 30, Company 2017 2016 2017 2016 (in millions) APCo $ 324.2 $ 325.5 $ 693.9 $ 709.9 I&M 390.7 384.1 809.0 772.2 OPCo 493.1 613.7 1,125.4 1,260.3 PSO 328.7 309.2 615.5 581.3 SWEPCo 404.6 387.4 745.8 723.5 |
Significant Accounting Matter35
Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Amounts Attributable to AEP Common Shareholders | ||||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | $ 376.2 | $ 506.4 | $ 970.4 | $ 1,009.5 |
Net Income Attributable to Noncontrolling Interests | 1.2 | 1.8 | 3.2 | 3.7 |
Income (Loss) from Continuing Operations Attributable to Parent | $ 375 | $ 504.6 | $ 967.2 | $ 1,005.8 |
Weighted Average Number of Basic AEP Common Shares Outstanding | 491,790,752 | 491,459,541 | 491,751,614 | 491,283,967 |
Basic Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations | $ 0.76 | $ 1.03 | $ 1.97 | $ 2.05 |
Weighted Average Dilutive Effect of: | ||||
Weighted Average Number of Diluted AEP Common Shares Outstanding | 492,642,100 | 491,641,400 | 492,337,255 | 491,486,853 |
Diluted Earnings Per Share Attributable to AEP Common Shareholders from Continuing Operations | $ 0.76 | $ 1.03 | $ 1.96 | $ 2.05 |
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Antidilutive Shares Outstanding | 0 | 0 | ||
Income (Loss) from Equity Method Investments Adjustment | $ 6.3 | |||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 442.3 | $ 425.4 | ||
Net Cash Paid (Received) for Income Taxes | (21.2) | 26.2 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 23.6 | 52.7 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | 597.9 | 554.2 | ||
Construction Expenditures Included in Noncurrent Liabilities as of June 30, | 71.8 | 0 | ||
Acquisition Of Nuclear Fuel Included In Current Liabilities as of June 30, | 26 | 41.5 | ||
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 2.4 | 0 | ||
AEP Transmission Co [Member] | ||||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 31.4 | 20.3 | ||
Net Cash Paid (Received) for Income Taxes | (67) | (178) | ||
Noncash Investing and Financing Activities: | ||||
Construction Expenditures Included in Current Liabilities as of June 30, | 190.3 | 155 | ||
Appalachian Power Co [Member] | ||||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 92.4 | 90.9 | ||
Net Cash Paid (Received) for Income Taxes | 32 | 28.3 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1.7 | 0.8 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | 99.1 | 69.1 | ||
Indiana Michigan Power Co [Member] | ||||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 49.2 | 40.3 | ||
Net Cash Paid (Received) for Income Taxes | (56.9) | (23.6) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 2.6 | 16.5 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | 96 | 89.8 | ||
Acquisition Of Nuclear Fuel Included In Current Liabilities as of June 30, | 26 | 41.5 | ||
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage | 2.5 | 0.1 | ||
Ohio Power Co [Member] | ||||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 50 | 60 | ||
Net Cash Paid (Received) for Income Taxes | 76.8 | 132.3 | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1.9 | 1.7 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | 50.3 | 23.1 | ||
Public Service Co Of Oklahoma [Member] | ||||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 31.7 | 30.2 | ||
Net Cash Paid (Received) for Income Taxes | (42.9) | (42) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 0.9 | 1.6 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | 29.2 | 24.3 | ||
Southwestern Electric Power Co [Member] | ||||
Amounts Attributable to AEP Common Shareholders | ||||
Net Income Attributable to Noncontrolling Interests | $ 0.6 | $ 1.1 | 1.6 | 2.2 |
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract] | ||||
Income (Loss) from Equity Method Investments Adjustment | 6.3 | |||
Cash Paid Received for [Abstract] | ||||
Cash Paid for Interest, Net of Capitalized Amounts | 66.8 | 57.5 | ||
Net Cash Paid (Received) for Income Taxes | (56.5) | (29.4) | ||
Noncash Investing and Financing Activities: | ||||
Noncash Acquisitions Under Capital Leases | 1.8 | 5.3 | ||
Construction Expenditures Included in Current Liabilities as of June 30, | $ 50.6 | $ 68.9 | ||
Restricted Stock Units and Performance Share Units [Member] | ||||
Weighted Average Dilutive Effect of: | ||||
Weighted Average Dilutive Effect of Shares | 800,000 | 100,000 | 500,000 | 200,000 |
Dilutive Securities, Effect on Basic Earnings Per Share | $ 0 | $ 0 | $ (0.01) | $ 0 |
Comprehensive Income (Details)
Comprehensive Income (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | $ (171) | $ (133.8) | $ (156.3) | $ (127.1) |
Change in Fair Value Recognized in AOCI | 3.5 | 17.7 | (17.1) | 10.2 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 67.7 | 53.2 | 106 | 88.8 |
Purchased Electricity for Resale | 669.2 | 629.2 | 1,438.8 | 1,360.6 |
Interest Expense | 222.9 | 224.9 | 444.7 | 441.9 |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 9 | (2.7) | 18 | (1.4) |
Income Tax (Expense) Credit | (190.6) | (165) | (533.8) | (400.5) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5.9 | (1.8) | 11.8 | (1) |
Net Current Period Other Comprehensive Income | 9.4 | 15.9 | (5.3) | 9.2 |
Ending Balance in AOCI | (161.6) | (117.9) | (161.6) | (117.9) |
Securities Available for Sale [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 9.6 | 7.7 | 8.4 | 7.1 |
Change in Fair Value Recognized in AOCI | 0.6 | 0.6 | 1.8 | 1.2 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Net Current Period Other Comprehensive Income | 0.6 | 0.6 | 1.8 | 1.2 |
Ending Balance in AOCI | 10.2 | 8.3 | 10.2 | 8.3 |
Pension and OPEB [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (125.7) | (111.7) | (125.9) | (111.8) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.4 | 0.2 | 0.8 | 0.4 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.3 | 0.1 | 0.5 | 0.2 |
Net Current Period Other Comprehensive Income | 0.3 | 0.1 | 0.5 | 0.2 |
Ending Balance in AOCI | (125.4) | (111.6) | (125.4) | (111.6) |
Commodity [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (39.6) | (12.9) | (23.1) | (5.2) |
Change in Fair Value Recognized in AOCI | (1.8) | 17.1 | (23.6) | 9 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 8.3 | (3.5) | 16.4 | (2.9) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 5.4 | (2.3) | 10.7 | (1.9) |
Net Current Period Other Comprehensive Income | 3.6 | 14.8 | (12.9) | 7.1 |
Ending Balance in AOCI | (36) | 1.9 | (36) | 1.9 |
Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (15.3) | (16.9) | (15.7) | (17.2) |
Change in Fair Value Recognized in AOCI | 4.7 | 0 | 4.7 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.3 | 0.6 | 0.8 | 1.1 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.2 | 0.4 | 0.6 | 0.7 |
Net Current Period Other Comprehensive Income | 4.9 | 0.4 | 5.3 | 0.7 |
Ending Balance in AOCI | (10.4) | (16.5) | (10.4) | (16.5) |
Reclassifications from Accumulated Other Comprehensive Income [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0 | (6.7) | (4.7) | (15.3) |
Purchased Electricity for Resale | 8.3 | 3.2 | 21.1 | 12.4 |
Interest Expense | 0.3 | 0.6 | 0.8 | 1.1 |
Prior Service Cost (Credit) | (4.9) | (4.9) | (9.8) | (9.8) |
Actuarial (Gains)/Losses | 5.3 | 5.1 | 10.6 | 10.2 |
Income Tax (Expense) Credit | 3.1 | (0.9) | 6.2 | (0.4) |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0 | 0 | 0 | 0 |
Purchased Electricity for Resale | 0 | 0 | 0 | 0 |
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0 | 0 | 0 | 0 |
Purchased Electricity for Resale | 0 | 0 | 0 | 0 |
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | (4.9) | (4.9) | (9.8) | (9.8) |
Actuarial (Gains)/Losses | 5.3 | 5.1 | 10.6 | 10.2 |
Income Tax (Expense) Credit | 0.1 | 0.1 | 0.3 | 0.2 |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0 | (6.7) | (4.7) | (15.3) |
Purchased Electricity for Resale | 8.3 | 3.2 | 21.1 | 12.4 |
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | 2.9 | (1.2) | 5.7 | (1) |
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0 | 0 | 0 | 0 |
Purchased Electricity for Resale | 0 | 0 | 0 | 0 |
Interest Expense | 0.3 | 0.6 | 0.8 | 1.1 |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | 0.1 | 0.2 | 0.2 | 0.4 |
AEP Transmission Co [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 15.7 | 10.5 | 31.7 | 21.3 |
Income Tax (Expense) Credit | (55.8) | (37) | (84.3) | (47.5) |
Appalachian Power Co [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (8.9) | (3.3) | (8.4) | (2.8) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 3.4 | 2.5 | 8.8 | 6.6 |
Purchased Electricity for Resale | 65.2 | 63.5 | 156 | 171.7 |
Interest Expense | 48.2 | 47.3 | 96.3 | 94.3 |
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.7) | (0.9) | (1.5) | (1.7) |
Income Tax (Expense) Credit | (29.9) | (41.1) | (93.5) | (114) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.5) | (0.6) | (1) | (1.1) |
Net Current Period Other Comprehensive Income | (0.5) | (0.6) | (1) | (1.1) |
Ending Balance in AOCI | (9.4) | (3.9) | (9.4) | (3.9) |
Appalachian Power Co [Member] | Pension and OPEB [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (11.6) | (6.7) | (11.3) | (6.4) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.4) | (0.6) | (0.9) | (1.1) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.3) | (0.4) | (0.6) | (0.7) |
Net Current Period Other Comprehensive Income | (0.3) | (0.4) | (0.6) | (0.7) |
Ending Balance in AOCI | (11.9) | (7.1) | (11.9) | (7.1) |
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 2.7 | 3.4 | 2.9 | 3.6 |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.3) | (0.3) | (0.6) | (0.6) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.2) | (0.2) | (0.4) | (0.4) |
Net Current Period Other Comprehensive Income | (0.2) | (0.2) | (0.4) | (0.4) |
Ending Balance in AOCI | 2.5 | 3.2 | 2.5 | 3.2 |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | (0.3) | (0.3) | (0.6) | (0.6) |
Prior Service Cost (Credit) | (1.3) | (1.4) | (2.6) | (2.6) |
Actuarial (Gains)/Losses | 0.9 | 0.8 | 1.7 | 1.5 |
Income Tax (Expense) Credit | (0.2) | (0.3) | (0.5) | (0.6) |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | (1.3) | (1.4) | (2.6) | (2.6) |
Actuarial (Gains)/Losses | 0.9 | 0.8 | 1.7 | 1.5 |
Income Tax (Expense) Credit | (0.1) | (0.2) | (0.3) | (0.4) |
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | (0.3) | (0.3) | (0.6) | (0.6) |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | (0.1) | (0.1) | (0.2) | (0.2) |
Indiana Michigan Power Co [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (15.9) | (16.3) | (16.2) | (16.7) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 3 | 4.3 | 6.3 | 9.8 |
Purchased Electricity for Resale | 31 | 41 | 68.3 | 90.6 |
Interest Expense | 27.8 | 27.1 | 55.5 | 49.6 |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.5 | 0.5 | 1 | 1 |
Income Tax (Expense) Credit | (4) | (25.1) | (33.2) | (49.2) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.4 | 0.3 | 0.7 | 0.7 |
Net Current Period Other Comprehensive Income | 0.4 | 0.3 | 0.7 | 0.7 |
Ending Balance in AOCI | (15.5) | (16) | (15.5) | (16) |
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (4.2) | (3.4) | (4.2) | (3.4) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Net Current Period Other Comprehensive Income | 0 | 0 | 0 | 0 |
Ending Balance in AOCI | (4.2) | (3.4) | (4.2) | (3.4) |
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (11.7) | (12.9) | (12) | (13.3) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.5 | 0.5 | 1 | 1 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.4 | 0.3 | 0.7 | 0.7 |
Net Current Period Other Comprehensive Income | 0.4 | 0.3 | 0.7 | 0.7 |
Ending Balance in AOCI | (11.3) | (12.6) | (11.3) | (12.6) |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0.5 | 0.5 | 1 | 1 |
Prior Service Cost (Credit) | (0.2) | (0.2) | (0.4) | (0.4) |
Actuarial (Gains)/Losses | 0.2 | 0.2 | 0.4 | 0.4 |
Income Tax (Expense) Credit | 0.1 | 0.2 | 0.3 | 0.3 |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | (0.2) | (0.2) | (0.4) | (0.4) |
Actuarial (Gains)/Losses | 0.2 | 0.2 | 0.4 | 0.4 |
Income Tax (Expense) Credit | 0 | 0 | 0 | 0 |
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0.5 | 0.5 | 1 | 1 |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | 0.1 | 0.2 | 0.3 | 0.3 |
Ohio Power Co [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 3 | |||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 1.4 | 1.3 | 3.4 | 3.4 |
Purchased Electricity for Resale | 156.4 | 147.8 | 344.7 | 312.7 |
Interest Expense | 26.1 | 29.1 | 51.1 | 60.5 |
Income Tax (Expense) Credit | (33.4) | (38.6) | (79.7) | (76.1) |
Net Current Period Other Comprehensive Income | (0.5) | (0.8) | ||
Ending Balance in AOCI | 2.5 | 2.5 | ||
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 2.8 | 3.9 | 3 | 4.3 |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.4) | (0.6) | (0.8) | (1.1) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.3) | (0.4) | (0.5) | (0.8) |
Net Current Period Other Comprehensive Income | (0.3) | (0.4) | (0.5) | (0.8) |
Ending Balance in AOCI | 2.5 | 3.5 | 2.5 | 3.5 |
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | (0.4) | (0.6) | (0.8) | (1.1) |
Income Tax (Expense) Credit | (0.1) | (0.2) | (0.3) | (0.3) |
Public Service Co Of Oklahoma [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 3.4 | |||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 1.1 | 0.7 | 2.2 | 2.2 |
Purchased Electricity for Resale | 126.7 | 91.2 | 252 | 184.5 |
Interest Expense | 13.4 | 15.3 | 27 | 29.7 |
Income Tax (Expense) Credit | (12.3) | (16.4) | (15.2) | (24.6) |
Net Current Period Other Comprehensive Income | (0.4) | (0.4) | ||
Ending Balance in AOCI | 3 | 3 | ||
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | 3.2 | 4 | 3.4 | 4.2 |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.3) | (0.3) | (0.6) | (0.6) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.2) | (0.2) | (0.4) | (0.4) |
Net Current Period Other Comprehensive Income | (0.2) | (0.2) | (0.4) | (0.4) |
Ending Balance in AOCI | 3 | 3.8 | 3 | 3.8 |
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | (0.3) | (0.3) | (0.6) | (0.6) |
Income Tax (Expense) Credit | (0.1) | (0.1) | (0.2) | (0.2) |
Southwestern Electric Power Co [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (9.1) | (9.1) | (9.4) | (9.4) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Other Revenues | 0.6 | 0.5 | 1 | 1 |
Purchased Electricity for Resale | 46.3 | 33.5 | 78.7 | 61.6 |
Interest Expense | 30.9 | 31.5 | 60.8 | 59.4 |
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.2 | 0.3 | 0.6 | 0.7 |
Income Tax (Expense) Credit | (13.2) | (13.3) | (22.7) | (20.7) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.1 | 0.2 | 0.4 | 0.5 |
Net Current Period Other Comprehensive Income | 0.1 | 0.2 | 0.4 | 0.5 |
Ending Balance in AOCI | (9) | (8.9) | (9) | (8.9) |
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (2.2) | (0.5) | (2) | (0.3) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | (0.2) | (0.3) | (0.5) | (0.6) |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | (0.1) | (0.2) | (0.3) | (0.4) |
Net Current Period Other Comprehensive Income | (0.1) | (0.2) | (0.3) | (0.4) |
Ending Balance in AOCI | (2.3) | (0.7) | (2.3) | (0.7) |
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Changes in Accumulated Other Comprehensive Income (Loss) by Component | ||||
Beginning Balance in AOCI | (6.9) | (8.6) | (7.4) | (9.1) |
Change in Fair Value Recognized in AOCI | 0 | 0 | 0 | 0 |
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Reclassifications from AOCI, before Income Tax (Expense) Credit | 0.4 | 0.6 | 1.1 | 1.3 |
Reclassifications from AOCI, Net of Income Tax (Expense) Credit | 0.2 | 0.4 | 0.7 | 0.9 |
Net Current Period Other Comprehensive Income | 0.2 | 0.4 | 0.7 | 0.9 |
Ending Balance in AOCI | (6.7) | (8.2) | (6.7) | (8.2) |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0.4 | 0.6 | 1.1 | 1.3 |
Prior Service Cost (Credit) | (0.5) | (0.5) | (1) | (1) |
Actuarial (Gains)/Losses | 0.3 | 0.2 | 0.5 | 0.4 |
Income Tax (Expense) Credit | 0.1 | 0.1 | 0.2 | 0.2 |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0 | 0 | 0 | 0 |
Prior Service Cost (Credit) | (0.5) | (0.5) | (1) | (1) |
Actuarial (Gains)/Losses | 0.3 | 0.2 | 0.5 | 0.4 |
Income Tax (Expense) Credit | (0.1) | (0.1) | (0.2) | (0.2) |
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member] | ||||
Reclassifications From Accumulated Other Comprehensive Income [Abstract] | ||||
Interest Expense | 0.4 | 0.6 | 1.1 | 1.3 |
Prior Service Cost (Credit) | 0 | 0 | 0 | 0 |
Actuarial (Gains)/Losses | 0 | 0 | 0 | 0 |
Income Tax (Expense) Credit | $ 0.2 | $ 0.2 | $ 0.4 | $ 0.4 |
Rate Matters - Regulatory Asset
Rate Matters - Regulatory Assets (Details) - USD ($) $ in Millions | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | $ 5,592.6 | $ 5,625.5 | |
Accumulated Depreciation and Amortization | 16,907.6 | 16,397.3 | |
AEP Transmission Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 133.5 | 112.3 | |
Accumulated Depreciation and Amortization | 133.1 | 99.6 | |
Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 1,106.9 | 1,121.1 | |
Accumulated Depreciation and Amortization | 3,762.8 | 3,636.8 | |
Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 901.6 | 916.6 | |
Accumulated Depreciation and Amortization | 3,014.1 | 3,005.1 | |
Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 1,058 | 1,107.5 | |
Accumulated Depreciation and Amortization | 2,164.3 | 2,116 | |
Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 391.7 | 340.2 | |
Accumulated Depreciation and Amortization | 1,362.9 | 1,272.7 | |
Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 567.6 | 551.2 | |
Accumulated Depreciation and Amortization | 2,634.4 | 2,567.1 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 421 | 450.1 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 46.9 | 39.3 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 71.4 | 64.7 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 100.8 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 185.4 | 118.1 | |
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 86.7 | 95.9 | |
Asset Retirement Obligation - Arkansas, Louisiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 3.3 | 2.7 | |
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 14.3 | 12.8 | |
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 14.3 | 12.8 | |
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 36.3 | 36.3 | |
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 36.3 | 36.3 | |
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 11.5 | 8.1 | |
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 11.5 | 8.1 | |
Environmental Control Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 20.4 | 24.1 | |
Environmental Control Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 20.4 | 13.1 | |
Environmental Control Projects [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 11 | |
Gridsmart Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 4.1 | |
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 96.7 | |
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0 | 96.7 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 1.1 | 1.3 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0.5 | 0.5 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0.5 | 0.8 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 21.2 | 21.2 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0.6 | 0.6 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 1 | 0.9 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 0.2 | 0 | |
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 2.1 | 1.9 | |
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 37.2 | 29.6 | |
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 37.2 | 29.6 | |
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 9.1 | 9.1 | |
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 9.1 | 9.1 | |
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Accumulated Depreciation and Amortization | 91 | ||
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Accumulated Depreciation and Amortization | 91 | ||
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 204.3 | 159.9 | |
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 128.9 | 84.5 | |
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 75.4 | 75.4 | |
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 2.1 | 1 | |
Rockport Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 8.3 | 6.6 | |
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 3.3 | 3.1 | |
Storm Related Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 24.4 | 25.1 | |
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 41.2 | 25.9 | |
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 35.4 | $ 20 | |
Northeastern Plant, Unit 3 [Member] | Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | 46 | $ 41 | |
Northeastern Plant, Unit 3 [Member] | Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Regulatory Assets, Noncurrent | $ 46 | $ 41 |
Rate Matters - East Companies
Rate Matters - East Companies (Details) $ in Millions | 1 Months Ended | 6 Months Ended | |
Jul. 27, 2017USD ($) | Jun. 30, 2017USD ($)MW | Dec. 31, 2016USD ($) | |
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | $ 3,336.8 | $ 3,183.9 | |
Appalachian Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | 397.8 | 390.3 | |
Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | 592.4 | 654.2 | |
Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Construction Work in Progress | $ 285.1 | $ 221.5 | |
FERC Transmission Complaint - AEP PJM Participants [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved Return on Common Equity | 10.99% | ||
Intervenor Recommended Return on Common Equity | 8.32% | ||
Kentucky Base Rate Case - 2017 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 66 | ||
Requested Return on Common Equity | 10.31% | ||
Requested Annual Increase in Environmental Surcharge | $ 4 | ||
Michigan Base Rate Case - 2017 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 52 | ||
Requested Return on Common Equity | 10.60% | ||
Amount of Increase Related to Annual Depreciation Rates | $ 23 | ||
Amount of Increase Related to Amortization of Regulatory Assets | 4 | ||
Michigan Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 52 | ||
Requested Return on Common Equity | 10.60% | ||
Amount of Increase Related to Annual Depreciation Rates | $ 23 | ||
Amount of Increase Related to Amortization of Regulatory Assets | $ 4 | ||
Ohio Electric Security Plan Filing [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved Return on Common Equity | 10.20% | ||
PUCO Approved Reduced Customer Credits | $ 15 | ||
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW | 400 | ||
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW | 500 | ||
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement | 100.00% | ||
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement | 50.00% | ||
Return on Common Equity Proposed in the Amended ESP Filing | 10.41% | ||
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Approved Return on Common Equity | 10.20% | ||
PUCO Approved Reduced Customer Credits | $ 15 | ||
Solar Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW | 400 | ||
Wind Energy Projects To Be Developed And Implemented By 2021 As Proposed In Stipulation Agreement | MW | 500 | ||
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement | 100.00% | ||
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement | 50.00% | ||
Return on Common Equity Proposed in the Amended ESP Filing | 10.41% | ||
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | $ 274 | ||
Construction Work in Progress | 9 | ||
Rockport Plant, Unit 2 Selective Catalytic Reduction [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Projected Capital Costs | 274 | ||
Construction Work in Progress | 9 | ||
2016 SEET Filing [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Provision for Refund | 58 | ||
2016 SEET Filing [Member] | Ohio Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Provision for Refund | $ 58 | ||
Subsequent Event [Member] | Indiana Base Rate Case - 2017 [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 263 | ||
Requested Return on Common Equity | 10.60% | ||
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider | $ 23 | ||
Amount of Increase Related to Annual Depreciation Rates | 78 | ||
Amount of Increase Related to Amortization of Regulatory Assets | 11 | ||
Subsequent Event [Member] | Indiana Base Rate Case - 2017 [Member] | Indiana Michigan Power Co [Member] | |||
Public Utilities, General Disclosures [Line Items] | |||
Requested Annual Increase | $ 263 | ||
Requested Return on Common Equity | 10.60% | ||
Amount Of Annual Reduction To Customer Bills Through Credit Adjustment Rider | $ 23 | ||
Amount of Increase Related to Annual Depreciation Rates | 78 | ||
Amount of Increase Related to Amortization of Regulatory Assets | $ 11 |
Rate Matters - West Companies (
Rate Matters - West Companies (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Public Utilities, General Disclosures [Line Items] | ||
Construction Work in Progress | $ 3,336.8 | $ 3,183.9 |
Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Construction Work in Progress | 111.2 | 148.2 |
Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Construction Work in Progress | 116.1 | $ 113.8 |
AEP Texas Interim Transmission and Distribution Rates [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
AEP Texas Cumulative Revenues Subject to Review | $ 635 | |
ETT Interim Transmission Rates [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Parent Ownership Interest In ETT | 50.00% | |
AEP Share Of ETT Cumulative Revenues Subject To Review | $ 672 | |
FERC Transmission Complaint - AEP SPP Participants [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Approved Return on Common Equity | 10.70% | |
Intervenor Recommended Return on Common Equity | 8.36% | |
2012 Texas Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
2013 Reversal of Previously Recorded Regulatory Disallowances | $ 114 | |
Resulting Approved Base Rate Increase | 52 | |
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
2013 Reversal of Previously Recorded Regulatory Disallowances | 114 | |
Resulting Approved Base Rate Increase | $ 52 | |
2016 Texas Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Return on Common Equity | 10.00% | |
Requested Net Increase in Texas Annual Revenues | $ 69 | |
Amount Of Increase Related To Environmental Controls | 34 | |
Amount of Increase Related to Additonal Investment and Increased Operating Costs | 25 | |
Amount of Increase Related to Transmission Cost Recovery | 8 | |
Amount of Increase Related to Vegetation Management | $ 2 | |
Texas Jurisdictional Share of the Welsh Plant | 33.00% | |
Recommended Investment Disallowances Resulting in Possible Write-Offs | $ 89 | |
Amount of Write-Off Related to Environmental Controls | 40 | |
Amount of Write-Off Related to Welsh Plant Unit 2 | $ 25 | |
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Return on Common Equity | 10.00% | |
Requested Net Increase in Texas Annual Revenues | $ 69 | |
Amount Of Increase Related To Environmental Controls | 34 | |
Amount of Increase Related to Additonal Investment and Increased Operating Costs | 25 | |
Amount of Increase Related to Transmission Cost Recovery | 8 | |
Amount of Increase Related to Vegetation Management | $ 2 | |
Texas Jurisdictional Share of the Welsh Plant | 33.00% | |
Recommended Investment Disallowances Resulting in Possible Write-Offs | $ 89 | |
Amount of Write-Off Related to Environmental Controls | 40 | |
Amount of Write-Off Related to Welsh Plant Unit 2 | $ 25 | |
Louisiana Turk Plant Prudence Review [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Louisiana Jurisdictional Share Of Turk Plant | 29.00% | |
Louisiana Turk Plant Prudence Review [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Louisiana Jurisdictional Share Of Turk Plant | 29.00% | |
Louisiana 2015 Formula Rate Filing [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | $ 14 | |
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | 14 | |
Louisiana 2017 Formula Rate Filing [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | 31 | |
Louisiana 2017 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | 31 | |
Oklahoma Base Rate Case - 2017 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | $ 156 | |
Requested Return on Common Equity | 10.00% | |
Amount of Increase Related to Annual Depreciation Rates | $ 42 | |
Oklahoma Base Rate Case - 2017 [Member] | Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Requested Annual Increase | $ 156 | |
Requested Return on Common Equity | 10.00% | |
Amount of Increase Related to Annual Depreciation Rates | $ 42 | |
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Property, Plant and Equipment, Net | 83 | |
Oklahoma Base Rate Case - 2017 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Property, Plant and Equipment, Net | 83 | |
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Projected Capital Costs | 850 | |
Construction Work in Progress | 398 | |
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs | 79 | |
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals | 11 | |
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity | 6 | |
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs | 131 | |
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Projected Capital Costs | 850 | |
Construction Work in Progress | 398 | |
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs | 79 | |
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals | 11 | |
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity | 6 | |
Amount Of Recovery Requested Related To Louisiana Retail Jurisdictional Share Of Environmental Costs | 131 | |
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Property, Plant and Equipment, Net | 628 | |
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Property, Plant and Equipment, Net | 628 | |
Minimum [Member] | 2016 Texas Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Recommended Net Increase in Texas Annual Revenues | $ 36 | |
Recommended Return on Equity | 9.20% | |
Minimum [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Recommended Net Increase in Texas Annual Revenues | $ 36 | |
Recommended Return on Equity | 9.20% | |
Maximum [Member] | 2016 Texas Base Rate Case [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Recommended Net Increase in Texas Annual Revenues | $ 47 | |
Recommended Return on Equity | 9.35% | |
Maximum [Member] | 2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member] | ||
Public Utilities, General Disclosures [Line Items] | ||
Recommended Net Increase in Texas Annual Revenues | $ 47 | |
Recommended Return on Equity | 9.35% |
Commitments, Guarantees and C40
Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions | 6 Months Ended | |
Jun. 30, 2017 | Dec. 31, 2016 | |
Letters of Credit [Member] | ||
Maximum Future Payments for Letters of Credit [Abstract] | ||
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility | $ 138.7 | |
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract] | ||
Variable Rate PCBs Supported | 45 | |
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Letters of Credit Limit | 1,200 | |
Uncommitted Facility | 370 | |
Bilateral Letters of Credit, Matured | 46 | |
Guarantees of Third Party Obligations [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Guarantees of Mine Reclamation, Amount | 115 | |
Estimated Final Cost Mine Reclamation | 74 | |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 70 | |
Amount Collected, Rider Mine Close Other Assets Noncurrent | 4 | |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 74 | |
Guarantees of Equity Method Investees [Member] | ||
Maximum Potential Amount of Future Payments Associated with Guarantee | $ 75 | |
Master Lease Agreements [Member] | ||
Maximum Potential Loss on Master Lease Agreements [Abstract] | ||
Max Potential Loss on Master Lease Agreements | 38 | |
Boat and Barge Leases [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases | 80 | |
Guarantee Liability related to AEPRO Boat and Barge Leases | 12 | |
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Current Liabilities | 2 | |
Guarantee Liability related to AEPRO Boat and Barge Leases - Other Noncurrent Liabilities | 10 | |
Appalachian Power Co [Member] | Master Lease Agreements [Member] | ||
Maximum Potential Loss on Master Lease Agreements [Abstract] | ||
Max Potential Loss on Master Lease Agreements | 5.6 | |
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member] | ||
Maximum Potential Loss on Master Lease Agreements [Abstract] | ||
Max Potential Loss on Master Lease Agreements | 3.2 | |
Indiana Michigan Power Co [Member] | Railcar Lease [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Future Minimum Lease Obligations for Remaining Railcars | $ 8 | |
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 | $ 8 | |
Ohio Power Co [Member] | Letters of Credit [Member] | ||
Maximum Future Payments for Letters of Credit [Abstract] | ||
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility | 0.6 | |
Ohio Power Co [Member] | Master Lease Agreements [Member] | ||
Maximum Potential Loss on Master Lease Agreements [Abstract] | ||
Max Potential Loss on Master Lease Agreements | 5.9 | |
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 | 3.2 | |
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Guarantees of Mine Reclamation, Amount | 115 | |
Estimated Final Cost Mine Reclamation | 74 | |
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs | 70 | |
Amount Collected, Rider Mine Close Other Assets Noncurrent | 4 | |
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent | 74 | |
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member] | ||
Maximum Potential Loss on Master Lease Agreements [Abstract] | ||
Max Potential Loss on Master Lease Agreements | 3.6 | |
Southwestern Electric Power Co [Member] | Railcar Lease [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Future Minimum Lease Obligations for Remaining Railcars | $ 9 | |
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 | $ 10 | |
Superfund and State Remediation [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Expense Recorded Due to Remediation Work Remaining Provision | 4 | |
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Expense Recorded Due to Remediation Work Remaining Provision | 4 | |
June 2021 [Member] | Letters of Credit [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Revolving Credit Facilities | 3,000 | |
June 2018 [Member] | Letters of Credit [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Revolving Credit Facilities | 500 | |
October 2017 [Member] | Letters of Credit [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Uncommitted Facility | 75 | |
April 2019 [Member] | Letters of Credit [Member] | ||
Commitments, Guarantees and Contingencies (Textuals) [Abstract] | ||
Uncommitted Facility | $ 100 |
Impairment, Disposition and A41
Impairment, Disposition and Assets and Liabilities Held for Sale (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income | $ 0 | $ (2.5) | $ 0 | $ (2.5) | |
Total Assets Classified as Held for Sale on the Balance Sheets | $ 1,951.2 | ||||
Total Liabilities Classified as Held for Sale on the Balance Sheets | 235.9 | ||||
Discontinued Operations and Disposal Groups (Textuals) | |||||
Asset Impairments and Other Related Charges | 1.9 | 0 | 13.1 | 0 | |
Generation And Marketing [Member] | |||||
Total Income on Discontinued Operations as Presented on the Condensed Consolidated Statements of Income | $ 0 | 0 | 0 | 0 | |
Fuel | 145.5 | ||||
Materials and Supplies | 49.4 | ||||
Property, Plant and Equipment - Net | 1,756.2 | ||||
Other Class of Assets That Are Not Major | 0.1 | ||||
Total Assets Classified as Held for Sale on the Balance Sheets | 1,951.2 | ||||
Long-term Debt | 134.8 | ||||
Waterford Plant Upgrade Liability | 52.2 | ||||
Asset Retirement Obligations | 36.7 | ||||
Other Classes of Liabilities That Are Not Major | 12.2 | ||||
Total Liabilities Classified as Held for Sale on the Balance Sheets | $ 235.9 | ||||
Discontinued Operations and Disposal Groups (Textuals) | |||||
Cash Proceeds from Sale of Plants Gross | 2,200 | ||||
Cash Proceeds from Sale of Disposition Plants, Net | 1,200 | ||||
Pre-tax Gain on Sale of Plants | 226 | ||||
Income from Continuing Operations before Income Tax Expense and Equity Earnings of the Plants Sold | $ 81 | 42 | $ 196 | ||
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member] | |||||
Discontinued Operations and Disposal Groups (Textuals) | |||||
Asset Impairments and Other Related Charges | 4 | ||||
Generation And Marketing [Member] | Merchant Coal-Fired Generation Assets [Member] | Wm. H. Zimmer Generating Station [Member] | |||||
Discontinued Operations and Disposal Groups (Textuals) | |||||
Asset Impairments and Other Related Charges | $ 9 |
Benefit Plans (Details)
Benefit Plans (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Pension Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | $ 24.1 | $ 21.5 | $ 48.2 | $ 42.9 |
Interest Cost | 50.8 | 52.9 | 101.6 | 105.8 |
Expected Return on Plan Assets | (71.2) | (70) | (142.4) | (140.1) |
Amortization of Prior Service Cost (Credit) | 0.2 | 0.5 | 0.5 | 1.1 |
Amortization of Net Actuarial Loss | 20.7 | 20.9 | 41.4 | 41.9 |
Net Periodic Benefit Cost (Credit) | 24.6 | 25.8 | 49.3 | 51.6 |
Pension Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2.4 | 2 | 4.7 | 4 |
Interest Cost | 6.4 | 6.8 | 12.8 | 13.6 |
Expected Return on Plan Assets | (9) | (8.9) | (17.9) | (17.7) |
Amortization of Prior Service Cost (Credit) | 0 | 0.1 | 0.1 | 0.1 |
Amortization of Net Actuarial Loss | 2.6 | 2.7 | 5.2 | 5.4 |
Net Periodic Benefit Cost (Credit) | 2.4 | 2.7 | 4.9 | 5.4 |
Pension Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 3.5 | 3.1 | 7 | 6.1 |
Interest Cost | 6 | 6.4 | 12.1 | 12.7 |
Expected Return on Plan Assets | (8.7) | (8.4) | (17.3) | (16.8) |
Amortization of Prior Service Cost (Credit) | 0.1 | 0 | 0.1 | 0.1 |
Amortization of Net Actuarial Loss | 2.5 | 2.4 | 4.9 | 4.9 |
Net Periodic Benefit Cost (Credit) | 3.4 | 3.5 | 6.8 | 7 |
Pension Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1.9 | 1.7 | 3.8 | 3.3 |
Interest Cost | 4.9 | 5.1 | 9.7 | 10.3 |
Expected Return on Plan Assets | (7) | (7) | (14) | (13.9) |
Amortization of Prior Service Cost (Credit) | 0.1 | 0.1 | 0.1 | 0.1 |
Amortization of Net Actuarial Loss | 1.9 | 2 | 3.9 | 4 |
Net Periodic Benefit Cost (Credit) | 1.8 | 1.9 | 3.5 | 3.8 |
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 1.6 | 1.6 | 3.2 | 3.1 |
Interest Cost | 2.7 | 2.8 | 5.4 | 5.6 |
Expected Return on Plan Assets | (4) | (3.8) | (7.9) | (7.7) |
Amortization of Prior Service Cost (Credit) | 0 | 0 | 0 | 0.1 |
Amortization of Net Actuarial Loss | 1.1 | 1.1 | 2.2 | 2.2 |
Net Periodic Benefit Cost (Credit) | 1.4 | 1.7 | 2.9 | 3.3 |
Pension Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2.2 | 2.1 | 4.4 | 4.1 |
Interest Cost | 3 | 3.1 | 6.1 | 6.2 |
Expected Return on Plan Assets | (4.2) | (4.2) | (8.4) | (8.3) |
Amortization of Prior Service Cost (Credit) | 0 | 0.1 | 0 | 0.2 |
Amortization of Net Actuarial Loss | 1.2 | 1.2 | 2.4 | 2.4 |
Net Periodic Benefit Cost (Credit) | 2.2 | 2.3 | 4.5 | 4.6 |
Other Postretirement Benefit Plans [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 2.8 | 2.5 | 5.6 | 5.1 |
Interest Cost | 14.9 | 15.2 | 29.7 | 30.4 |
Expected Return on Plan Assets | (25.4) | (26.7) | (50.7) | (53.5) |
Amortization of Prior Service Cost (Credit) | (17.2) | (17.2) | (34.5) | (34.5) |
Amortization of Net Actuarial Loss | 9.1 | 7.8 | 18.3 | 15.7 |
Net Periodic Benefit Cost (Credit) | (15.8) | (18.4) | (31.6) | (36.8) |
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 0.2 | 0.3 | 0.5 | 0.5 |
Interest Cost | 2.7 | 2.7 | 5.3 | 5.4 |
Expected Return on Plan Assets | (4.1) | (4.4) | (8.2) | (8.7) |
Amortization of Prior Service Cost (Credit) | (2.5) | (2.5) | (5) | (5) |
Amortization of Net Actuarial Loss | 1.5 | 1.3 | 3.1 | 2.7 |
Net Periodic Benefit Cost (Credit) | (2.2) | (2.6) | (4.3) | (5.1) |
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 0.4 | 0.3 | 0.8 | 0.7 |
Interest Cost | 1.8 | 1.7 | 3.5 | 3.5 |
Expected Return on Plan Assets | (3) | (3.2) | (6.1) | (6.4) |
Amortization of Prior Service Cost (Credit) | (2.4) | (2.3) | (4.7) | (4.7) |
Amortization of Net Actuarial Loss | 1.1 | 1 | 2.2 | 1.9 |
Net Periodic Benefit Cost (Credit) | (2.1) | (2.5) | (4.3) | (5) |
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 0.2 | 0.2 | 0.4 | 0.4 |
Interest Cost | 1.7 | 1.8 | 3.4 | 3.5 |
Expected Return on Plan Assets | (3) | (3.2) | (6) | (6.4) |
Amortization of Prior Service Cost (Credit) | (1.8) | (1.8) | (3.5) | (3.5) |
Amortization of Net Actuarial Loss | 1.1 | 1 | 2.2 | 1.9 |
Net Periodic Benefit Cost (Credit) | (1.8) | (2) | (3.5) | (4.1) |
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 0.1 | 0.1 | 0.3 | 0.3 |
Interest Cost | 0.8 | 0.8 | 1.6 | 1.6 |
Expected Return on Plan Assets | (1.4) | (1.5) | (2.8) | (3) |
Amortization of Prior Service Cost (Credit) | (1) | (1) | (2.1) | (2.1) |
Amortization of Net Actuarial Loss | 0.5 | 0.5 | 1 | 0.9 |
Net Periodic Benefit Cost (Credit) | (1) | (1.1) | (2) | (2.3) |
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | ||||
Components of Net Periodic Benefit Cost | ||||
Service Cost | 0.2 | 0.2 | 0.4 | 0.4 |
Interest Cost | 0.9 | 0.9 | 1.8 | 1.8 |
Expected Return on Plan Assets | (1.6) | (1.6) | (3.2) | (3.3) |
Amortization of Prior Service Cost (Credit) | (1.3) | (1.3) | (2.6) | (2.6) |
Amortization of Net Actuarial Loss | 0.6 | 0.5 | 1.2 | 1 |
Net Periodic Benefit Cost (Credit) | $ (1.2) | $ (1.3) | $ (2.4) | $ (2.7) |
Business Segments (Details)
Business Segments (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | ||
Reportable Segment Information | ||||||
Revenue, Net | $ 3,576.5 | $ 3,892.9 | $ 7,509.8 | $ 7,937.8 | ||
Total Revenues | 3,576.5 | 3,892.9 | 7,509.8 | 7,937.8 | ||
Interest Expense | 222.9 | 224.9 | 444.7 | 441.9 | ||
Income Tax Expense | 190.6 | 165 | 533.8 | 400.5 | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 376.2 | 506.4 | 970.4 | 1,009.5 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | (2.5) | 0 | (2.5) | ||
Net Income (Loss) | 376.2 | 503.9 | 970.4 | 1,007 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 64,134.8 | 64,134.8 | $ 62,036.6 | |||
Accumulated Depreciation and Amortization | 16,907.6 | 16,907.6 | 16,397.3 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 47,227.2 | 47,227.2 | 45,639.3 | |||
Assets Held for Sale | 1,951.2 | |||||
Total Assets | 62,739.1 | 62,739.1 | 63,467.7 | |||
Long-term Debt Due Within One Year | 2,755 | 2,755 | 2,878 | |||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||
Long-term Debt | 16,796.9 | 16,796.9 | 17,378.4 | |||
Total Long-term Debt Outstanding | 19,551.9 | 19,551.9 | 20,256.4 | |||
Liabilities Held for Sale | 235.9 | |||||
Vertically Integrated Utilities [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 2,095.7 | 2,108.2 | 4,365.5 | 4,326.3 | ||
Total Revenues | 2,120.5 | 2,125.9 | 4,410.9 | 4,371.5 | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 121.4 | 210.5 | 341.9 | 489.2 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 121.4 | 210.5 | 341.9 | 489.2 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 42,313.2 | 42,313.2 | 41,552.6 | |||
Accumulated Depreciation and Amortization | 12,880 | 12,880 | 12,596.7 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 29,433.2 | 29,433.2 | 28,955.9 | |||
Assets Held for Sale | 0 | |||||
Total Assets | 37,914.1 | 37,914.1 | 37,428.3 | |||
Long-term Debt Due Within One Year | 1,449.6 | 1,449.6 | 1,519.9 | |||
Long-term Debt - Affiliated | 40 | 40 | 20 | |||
Long-term Debt | 10,347.5 | 10,347.5 | 10,353.3 | |||
Total Long-term Debt Outstanding | 11,837.1 | 11,837.1 | 11,893.2 | |||
Liabilities Held for Sale | 0 | |||||
Transmission And Distribution Utilities [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 1,026.6 | 1,076.2 | 2,093 | 2,153.5 | ||
Total Revenues | 1,053.5 | 1,096.1 | 2,139.9 | 2,192.9 | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 111.2 | 124.6 | 230.3 | 232.1 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 111.2 | 124.6 | 230.3 | 232.1 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 15,292 | 15,292 | 14,762.2 | |||
Accumulated Depreciation and Amortization | 3,737.9 | 3,737.9 | 3,655 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 11,554.1 | 11,554.1 | 11,107.2 | |||
Assets Held for Sale | 0 | |||||
Total Assets | 15,092.4 | 15,092.4 | 14,802.4 | |||
Long-term Debt Due Within One Year | 756.9 | 756.9 | 309.4 | |||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||
Long-term Debt | 4,088 | 4,088 | 4,672.2 | |||
Total Long-term Debt Outstanding | 4,844.9 | 4,844.9 | 4,981.6 | |||
Liabilities Held for Sale | 0 | |||||
AEP Transmission Holdco [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 53 | 41.3 | 80.7 | 70.6 | ||
Total Revenues | 247.3 | 161.7 | 403.4 | 250.3 | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 129 | 95.3 | 201.8 | 140 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 129 | 95.3 | 201.8 | 140 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 6,012.1 | 6,012.1 | 5,354 | |||
Accumulated Depreciation and Amortization | 137 | 137 | 101.4 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,875.1 | 5,875.1 | 5,252.6 | |||
Assets Held for Sale | 0 | |||||
Total Assets | 7,024.9 | 7,024.9 | 6,384.8 | |||
Long-term Debt Due Within One Year | 0 | 0 | 0 | |||
Long-term Debt - Affiliated | 0 | 0 | 0 | |||
Long-term Debt | 2,063.5 | 2,063.5 | 2,055.7 | |||
Total Long-term Debt Outstanding | 2,063.5 | 2,063.5 | 2,055.7 | |||
Liabilities Held for Sale | 0 | |||||
Generation And Marketing [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 386.5 | 655.3 | 945.3 | 1,369.2 | ||
Total Revenues | 410.6 | 683.8 | 1,002 | 1,431.8 | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 26.4 | 49.7 | 212.6 | 120.4 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 26.4 | 49.7 | 212.6 | 120.4 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 518.4 | 518.4 | 364.7 | |||
Accumulated Depreciation and Amortization | 145.1 | 145.1 | 42.2 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 373.3 | 373.3 | 322.5 | |||
Assets Held for Sale | 1,951.2 | |||||
Total Assets | 1,905.7 | 1,905.7 | 3,386.1 | |||
Long-term Debt Due Within One Year | 0 | 0 | 500.1 | |||
Long-term Debt - Affiliated | 32.2 | 32.2 | 32.2 | |||
Long-term Debt | 0 | 0 | 0 | |||
Total Long-term Debt Outstanding | 32.2 | 32.2 | 532.3 | |||
Liabilities Held for Sale | 235.9 | |||||
All Other [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | [1] | 14.7 | 11.9 | 25.3 | 18.2 | |
Total Revenues | [1] | 28.9 | 29.9 | 55.4 | 54.3 | |
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | [1] | (11.8) | 26.3 | (16.2) | 27.8 | |
Income (Loss) from Discontinued Operations, Net of Tax | [1] | 0 | (2.5) | 0 | (2.5) | |
Net Income (Loss) | [1] | (11.8) | 23.8 | (16.2) | 25.3 | |
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | [1] | 365.6 | 365.6 | 356.6 | ||
Accumulated Depreciation and Amortization | [1] | 194 | 194 | 186 | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | [1] | 171.6 | 171.6 | 170.6 | ||
Assets Held for Sale | 0 | |||||
Total Assets | [1] | 21,147.9 | 21,147.9 | 20,354.8 | ||
Long-term Debt Due Within One Year | [1] | 548.5 | 548.5 | 548.6 | ||
Long-term Debt - Affiliated | [1] | 0 | 0 | 0 | ||
Long-term Debt | [1] | 297.9 | 297.9 | 297.2 | ||
Total Long-term Debt Outstanding | [1] | 846.4 | 846.4 | 845.8 | ||
Liabilities Held for Sale | 0 | |||||
Consolidation, Eliminations [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 0 | 0 | 0 | 0 | ||
Total Revenues | (284.3) | (204.5) | (501.8) | (363) | ||
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest | 0 | 0 | 0 | 0 | ||
Income (Loss) from Discontinued Operations, Net of Tax | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 0 | 0 | 0 | 0 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | [2] | (366.5) | (366.5) | (353.5) | ||
Accumulated Depreciation and Amortization | [2] | (186.4) | (186.4) | (184) | ||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | [2] | (180.1) | (180.1) | (169.5) | ||
Assets Held for Sale | 0 | |||||
Total Assets | [2],[3] | (20,345.9) | (20,345.9) | (18,888.7) | ||
Long-term Debt Due Within One Year | 0 | 0 | 0 | |||
Long-term Debt - Affiliated | (72.2) | (72.2) | (52.2) | |||
Long-term Debt | 0 | 0 | 0 | |||
Total Long-term Debt Outstanding | (72.2) | (72.2) | (52.2) | |||
Liabilities Held for Sale | 0 | |||||
Segment Reconciling Items [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | (284.3) | (204.5) | (501.8) | (363) | ||
Segment Reconciling Items [Member] | Vertically Integrated Utilities [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 24.8 | 17.7 | 45.4 | 45.2 | ||
Segment Reconciling Items [Member] | Transmission And Distribution Utilities [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 26.9 | 19.9 | 46.9 | 39.4 | ||
Segment Reconciling Items [Member] | AEP Transmission Holdco [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 194.3 | 120.4 | 322.7 | 179.7 | ||
Segment Reconciling Items [Member] | Generation And Marketing [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | 24.1 | 28.5 | 56.7 | 62.6 | ||
Segment Reconciling Items [Member] | All Other [Member] | ||||||
Reportable Segment Information | ||||||
Revenue, Net | [1] | 14.2 | 18 | 30.1 | 36.1 | |
AEP Transmission Co [Member] | ||||||
Reportable Segment Information | ||||||
External Customers | 44 | 34.1 | 63.3 | 56.1 | ||
Sales to AEP Affiliates | 185.4 | 119 | 318.8 | 176.6 | ||
Total Revenues | 229.4 | 153.1 | 382.1 | 232.7 | ||
Interest Income - Affiliated | 0.1 | 0.1 | 0.3 | 0.1 | ||
Interest Expense | 15.7 | 10.5 | 31.7 | 21.3 | ||
Income Tax Expense | 55.8 | 37 | 84.3 | 47.5 | ||
Equity Earnings in State Transcos | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 107.4 | 74.8 | 164.4 | 100.6 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 5,690.3 | 5,690.3 | 5,054.2 | |||
Accumulated Depreciation and Amortization | 133.1 | 133.1 | 99.6 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,557.2 | 5,557.2 | 4,954.6 | |||
Notes Receivable, Related Parties | 0 | 0 | 0 | |||
Total Assets | 5,943.6 | 5,943.6 | 5,349.8 | |||
Long-term Debt | 1,931.4 | 1,931.4 | 1,932 | |||
Total Long-term Debt Outstanding | 1,931.4 | 1,931.4 | 1,932 | |||
AEP Transmission Co [Member] | State Transcos [Member] | ||||||
Reportable Segment Information | ||||||
External Customers | 44 | 34.1 | 63.3 | 56.1 | ||
Sales to AEP Affiliates | 185.5 | 119 | 318.9 | 176.6 | ||
Total Revenues | 229.5 | 153.1 | 382.2 | 232.7 | ||
Interest Income - Affiliated | 0 | 0 | 0.1 | 0 | ||
Interest Expense | 15.9 | 10.5 | 31.7 | 21.3 | ||
Income Tax Expense | 55.7 | 37 | 84.1 | 47.5 | ||
Equity Earnings in State Transcos | 0 | 0 | 0 | 0 | ||
Net Income (Loss) | 107.4 | 74.8 | 164.2 | 100.6 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 5,690.3 | 5,690.3 | 5,054.2 | |||
Accumulated Depreciation and Amortization | 133.1 | 133.1 | 99.6 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 5,557.2 | 5,557.2 | 4,954.6 | |||
Notes Receivable, Related Parties | 0 | 0 | 0 | |||
Total Assets | 5,924.5 | 5,924.5 | 5,337.5 | |||
Total Long-term Debt Outstanding | 1,931.4 | 1,931.4 | 1,932 | |||
AEP Transmission Co [Member] | AEPTCo Parent [Member] | ||||||
Reportable Segment Information | ||||||
External Customers | 0 | 0 | 0 | 0 | ||
Sales to AEP Affiliates | 0 | 0 | 0 | 0 | ||
Total Revenues | 0 | 0 | 0 | 0 | ||
Interest Income - Affiliated | 19.4 | 13.9 | 38.5 | 27.8 | ||
Interest Expense | 19.1 | 13.9 | 38.3 | 27.7 | ||
Income Tax Expense | 0.1 | 0 | 0.2 | 0 | ||
Equity Earnings in State Transcos | 107.4 | 74.8 | 164.2 | 100.6 | ||
Net Income (Loss) | 107.4 | 74.8 | 164.4 | 100.6 | ||
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 0 | 0 | 0 | |||
Accumulated Depreciation and Amortization | 0 | 0 | 0 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 0 | 0 | 0 | |||
Notes Receivable, Related Parties | 1,950 | 1,950 | 1,950 | |||
Total Assets | 4,282.5 | 4,282.5 | 3,947.8 | |||
Total Long-term Debt Outstanding | 1,950 | 1,950 | 1,950 | |||
AEP Transmission Co [Member] | Consolidation, Eliminations [Member] | ||||||
Reportable Segment Information | ||||||
External Customers | 0 | 0 | 0 | 0 | ||
Sales to AEP Affiliates | (0.1) | 0 | (0.1) | 0 | ||
Total Revenues | (0.1) | 0 | (0.1) | 0 | ||
Interest Income - Affiliated | [4] | (19.3) | (13.8) | (38.3) | (27.7) | |
Interest Expense | [4] | (19.3) | (13.9) | (38.3) | (27.7) | |
Income Tax Expense | 0 | 0 | 0 | 0 | ||
Equity Earnings in State Transcos | [5] | (107.4) | (74.8) | (164.2) | (100.6) | |
Net Income (Loss) | [5] | (107.4) | $ (74.8) | (164.2) | $ (100.6) | |
Balance Sheet Information | ||||||
Total Property, Plant and Equipment | 0 | 0 | 0 | |||
Accumulated Depreciation and Amortization | 0 | 0 | 0 | |||
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET | 0 | 0 | 0 | |||
Notes Receivable, Related Parties | [6] | (1,950) | (1,950) | (1,950) | ||
Total Assets | [7] | (4,263.4) | (4,263.4) | (3,935.5) | ||
Total Long-term Debt Outstanding | [6] | $ (1,950) | $ (1,950) | $ (1,950) | ||
[1] | Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. | |||||
[2] | Includes eliminations due to an intercompany capital lease. | |||||
[3] | 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. | |||||
[4] | Elimination of intercompany interest income/interest expense on affiliated debt arrangement. | |||||
[5] | Elimination of AEPTCo Parent’s equity earnings in the State Transcos. | |||||
[6] | Elimination of intercompany debt. | |||||
[7] | Primarily relates to the elimination of AEPTCo Parent’s investment in the State Transcos and Notes Receivable from the State Transcos. |
Derivatives and Hedging (Detail
Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||
Jun. 30, 2017USD ($)MWhMMBTUTgal | Jun. 30, 2016USD ($) | Jun. 30, 2017USD ($)MWhMMBTUTgal | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($)MWhMMBTUTgal | |||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | $ 9.2 | $ 9.2 | $ 7.9 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 24 | 24 | 7.6 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 170.5 | 170.5 | 94.5 | ||||||
Long-term Risk Management Assets | 285.6 | 285.6 | 289.1 | ||||||
Total Assets | 456.1 | 456.1 | 383.6 | ||||||
Current Risk Management Liabilities | 61.7 | 61.7 | 53.4 | ||||||
Long-term Risk Management Liabilities | 310.6 | 310.6 | 316.2 | ||||||
Total Liabilities | 372.3 | 372.3 | 369.6 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 50.6 | $ 24.7 | 79.7 | $ 43.8 | |||||
Gain (Loss) on Hedging Instruments | |||||||||
Gain (Loss) on Fair Value Hedging Instruments | 0.4 | 0.6 | (0.1) | 4.1 | |||||
Gain (Loss) on Fair Value Portion of Long Term Debt | (0.4) | (0.6) | 0.1 | (4.1) | |||||
Collateral Triggering Events [Abstract] | |||||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 38.7 | 38.7 | 9.3 | ||||||
Amount of Collateral Attributable to Other Contracts | [1] | 197.3 | 197.3 | 280.3 | |||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 247 | 247 | 259.6 | ||||||
Amount of Cash Collateral Posted | 2.3 | 2.3 | 0.4 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 234.1 | $ 234.1 | 235.8 | ||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Maximum Term for Exposure to Variability of Future Cash Flows | 126 months | ||||||||
Appalachian Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 2.1 | $ 2.1 | 0.5 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0.1 | 0.1 | 0.7 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 41.6 | 41.6 | 2.6 | ||||||
Current Risk Management Liabilities | 0.4 | 0.4 | 0.3 | ||||||
Long-term Risk Management Liabilities | 0.4 | 0.4 | 0.9 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 19.7 | (5.7) | 26 | 11.8 | |||||
Collateral Triggering Events [Abstract] | |||||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 7.4 | 7.4 | 1 | ||||||
Amount of Collateral Attributable to Other Contracts | 0 | 0 | 0 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 0 | 0 | 0.1 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | 0 | 0 | ||||||
Indiana Michigan Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 2.3 | 2.3 | 0.3 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | 0 | 0.4 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 15.8 | 15.8 | 3.5 | ||||||
Current Risk Management Liabilities | 0.9 | 0.9 | 0.3 | ||||||
Long-term Risk Management Liabilities | 0.2 | 0.2 | 0.8 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 7.1 | 5.6 | 19 | 15.3 | |||||
Collateral Triggering Events [Abstract] | |||||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 4.5 | 4.5 | 0.6 | ||||||
Amount of Collateral Attributable to Other Contracts | 0 | 0 | 0 | ||||||
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements | 0 | 0 | 0.1 | ||||||
Amount of Cash Collateral Posted | 0 | 0 | 0 | ||||||
Additional Settlement Liability if Cross Default Provision is Triggered | 0 | 0 | 0 | ||||||
Ohio Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0.2 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 0 | 0 | 0.2 | ||||||
Current Risk Management Liabilities | 7.1 | 7.1 | 5.9 | ||||||
Long-term Risk Management Liabilities | 123.5 | 123.5 | 113.1 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | (8.6) | (5.8) | (17.2) | (36.1) | |||||
Public Service Co Of Oklahoma [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0.1 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 9.5 | 9.5 | 0.8 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 8.7 | 3.2 | 11.1 | 2.5 | |||||
Collateral Triggering Events [Abstract] | |||||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 3.7 | 3.7 | 2.1 | ||||||
Amount of Collateral Attributable to Other Contracts | 3.3 | 3.3 | 3.2 | ||||||
Southwestern Electric Power Co [Member] | |||||||||
Cash Collateral Netting | |||||||||
Cash Collateral Received Netted Against Risk Management Assets | 0 | 0 | 0.1 | ||||||
Cash Collateral Paid Netted Against Risk Management Liabilities | 0 | 0 | 0 | ||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 12.5 | 12.5 | 0.9 | ||||||
Current Risk Management Liabilities | 0.5 | 0.5 | 0.3 | ||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 10.4 | 9 | 14.9 | 13.4 | |||||
Collateral Triggering Events [Abstract] | |||||||||
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs | 6.2 | 6.2 | 2.5 | ||||||
Amount of Collateral Attributable to Other Contracts | 0.1 | 0.1 | 0.1 | ||||||
Risk Management Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2] | 447.3 | [3] | 447.3 | [3] | 372.4 | [4] | ||
Total Liabilities | [2] | 311.6 | [3] | 311.6 | [3] | 321.5 | [4] | ||
Risk Management Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2],[5] | 41.6 | 41.6 | 2.6 | |||||
Total Liabilities | [2],[5] | 0.8 | 0.8 | 1.2 | |||||
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2],[5] | 15.8 | 15.8 | 3.5 | |||||
Total Liabilities | [2],[5] | 1.1 | 1.1 | 1.1 | |||||
Risk Management Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2],[5] | 0.2 | |||||||
Total Liabilities | [2],[5] | 130.6 | 130.6 | 119 | |||||
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2],[5] | 9.5 | 9.5 | 0.8 | |||||
Total Liabilities | [2],[5] | 0 | 0 | ||||||
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Total Assets | [2],[5] | 12.5 | 12.5 | 0.9 | |||||
Total Liabilities | [2],[5] | 0.5 | 0.5 | 0.3 | |||||
Commodity [Member] | |||||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [6] | 4 | 4 | 11.2 | |||||
Hedging Liabilities | [6] | 59.2 | 59.2 | 46.7 | |||||
AOCI Gain (Loss) Net of Tax | (36) | (36) | (23.1) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (2.7) | 4.3 | |||||||
Derivatives and Hedging (Textuals) [Abstract] | |||||||||
Cross Default Provisions Maximum Third Party Obligation Amount | 50 | 50 | 50 | ||||||
Commodity [Member] | Risk Management Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 366 | 366 | 264.4 | |||||
Long-term Risk Management Assets | [7] | 340.6 | 340.6 | 315 | |||||
Total Assets | [7] | 706.6 | 706.6 | 579.4 | |||||
Current Risk Management Liabilities | [7] | 260.1 | 260.1 | 227.2 | |||||
Long-term Risk Management Liabilities | [7] | 325.6 | 325.6 | 301 | |||||
Total Liabilities | [7] | 585.7 | 585.7 | 528.2 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 120.9 | 120.9 | 51.2 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 72.3 | 72.3 | 22.7 | |||||
Long-term Risk Management Assets | [7] | 6.6 | 6.6 | 1.9 | |||||
Total Assets | [7] | 78.9 | 78.9 | 24.6 | |||||
Current Risk Management Liabilities | [7] | 29.5 | 29.5 | 20.6 | |||||
Long-term Risk Management Liabilities | [7] | 6.6 | 6.6 | 2.8 | |||||
Total Liabilities | [7] | 36.1 | 36.1 | 23.4 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 42.8 | 42.8 | 1.2 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 37.9 | 37.9 | 14.9 | |||||
Long-term Risk Management Assets | [7] | 4.2 | 4.2 | 1.1 | |||||
Total Assets | [7] | 42.1 | 42.1 | 16 | |||||
Current Risk Management Liabilities | [7] | 21.1 | 21.1 | 11.8 | |||||
Long-term Risk Management Liabilities | [7] | 4 | 4 | 1.9 | |||||
Total Liabilities | [7] | 25.1 | 25.1 | 13.7 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 17 | 17 | 2.3 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 0 | 0 | 0.4 | |||||
Long-term Risk Management Assets | [7] | 0 | 0 | 0 | |||||
Total Assets | [7] | 0 | 0 | 0.4 | |||||
Current Risk Management Liabilities | [7] | 7.1 | 7.1 | 5.9 | |||||
Long-term Risk Management Liabilities | [7] | 123.5 | 123.5 | 113.1 | |||||
Total Liabilities | [7] | 130.6 | 130.6 | 119 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | (130.6) | (130.6) | (118.6) | |||||
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 9.9 | 9.9 | 0.9 | |||||
Long-term Risk Management Assets | [7] | 0 | 0 | 0 | |||||
Total Assets | [7] | 9.9 | 9.9 | 0.9 | |||||
Current Risk Management Liabilities | [7] | 0.4 | 0.4 | 0 | |||||
Long-term Risk Management Liabilities | [7] | 0 | 0 | 0 | |||||
Total Liabilities | [7] | 0.4 | 0.4 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 9.5 | 9.5 | 0.9 | |||||
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 12.9 | 12.9 | 1.1 | |||||
Long-term Risk Management Assets | [7] | 0 | 0 | 0 | |||||
Total Assets | [7] | 12.9 | 12.9 | 1.1 | |||||
Current Risk Management Liabilities | [7] | 0.9 | 0.9 | 0.4 | |||||
Long-term Risk Management Liabilities | [7] | 0 | 0 | 0 | |||||
Total Liabilities | [7] | 0.9 | 0.9 | 0.4 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 12 | 12 | 0.7 | |||||
Commodity [Member] | Hedging Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 8.1 | 8.1 | 13.2 | |||||
Long-term Risk Management Assets | [7] | 4.1 | 4.1 | 7.7 | |||||
Total Assets | [7] | 12.2 | 12.2 | 20.9 | |||||
Current Risk Management Liabilities | [7] | 12.1 | 12.1 | 6.3 | |||||
Long-term Risk Management Liabilities | [7] | 55.3 | 55.3 | 50.1 | |||||
Total Liabilities | [7] | 67.4 | 67.4 | 56.4 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | (55.2) | (55.2) | (35.5) | |||||
Interest Rate [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 1,000 | 1,000 | 500 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
Hedging Assets | [6] | 4.8 | 4.8 | 0 | |||||
Hedging Liabilities | [6] | 0 | 0 | 0 | |||||
AOCI Gain (Loss) Net of Tax | (10.4) | (10.4) | (15.7) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (0.7) | (1) | |||||||
Interest Rate [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
AOCI Gain (Loss) Net of Tax | 2.5 | 2.5 | 2.9 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0.7 | 0.7 | |||||||
Interest Rate [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
AOCI Gain (Loss) Net of Tax | (11.3) | (11.3) | (12) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (1.3) | (1.3) | |||||||
Interest Rate [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
AOCI Gain (Loss) Net of Tax | 2.5 | 2.5 | 3 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 1.1 | 1.1 | |||||||
Interest Rate [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
AOCI Gain (Loss) Net of Tax | 3 | 3 | 3.4 | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | 0.8 | 0.8 | |||||||
Interest Rate [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Impact of Cash Flow Hedges on the Condensed Balance Sheet | |||||||||
AOCI Gain (Loss) Net of Tax | (6.7) | (6.7) | (7.4) | ||||||
Portion Expected to be Reclassified to Net Income During the Next Twelve Months | (1.4) | (1.4) | |||||||
Interest Rate [Member] | Hedging Contracts [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [7] | 4.8 | 4.8 | 0 | |||||
Long-term Risk Management Assets | [7] | 0 | 0 | 0 | |||||
Total Assets | [7] | 4.8 | 4.8 | 0 | |||||
Current Risk Management Liabilities | [7] | 1.5 | 1.5 | 0 | |||||
Long-term Risk Management Liabilities | [7] | 0 | 0 | 1.4 | |||||
Total Liabilities | [7] | 1.5 | 1.5 | 1.4 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [7] | 3.3 | 3.3 | (1.4) | |||||
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | 378.9 | 378.9 | 277.6 | ||||||
Long-term Risk Management Assets | 344.7 | 344.7 | 322.7 | ||||||
Total Assets | 723.6 | 723.6 | 600.3 | ||||||
Current Risk Management Liabilities | 273.7 | 273.7 | 233.5 | ||||||
Long-term Risk Management Liabilities | 380.9 | 380.9 | 352.5 | ||||||
Total Liabilities | 654.6 | 654.6 | 586 | ||||||
Total MTM Derivative Contract Net Assets (Liabilities) | 69 | 69 | 14.3 | ||||||
Gross Amounts Offset in the Statement of Financial Position [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [8] | (208.4) | (208.4) | (183.1) | |||||
Long-term Risk Management Assets | [8] | (59.1) | (59.1) | (33.6) | |||||
Total Assets | [8] | (267.5) | (267.5) | (216.7) | |||||
Current Risk Management Liabilities | [8] | (212) | (212) | (180.1) | |||||
Long-term Risk Management Liabilities | [8] | (70.3) | (70.3) | (36.3) | |||||
Total Liabilities | [8] | (282.3) | (282.3) | (216.4) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | 14.8 | 14.8 | (0.3) | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [8] | (30.7) | (30.7) | (20.1) | |||||
Long-term Risk Management Assets | [8] | (6.6) | (6.6) | (1.9) | |||||
Total Assets | [8] | (37.3) | (37.3) | (22) | |||||
Current Risk Management Liabilities | [8] | (29.1) | (29.1) | (20.3) | |||||
Long-term Risk Management Liabilities | [8] | (6.2) | (6.2) | (1.9) | |||||
Total Liabilities | [8] | (35.3) | (35.3) | (22.2) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | (2) | (2) | 0.2 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [8] | (22.1) | (22.1) | (11.4) | |||||
Long-term Risk Management Assets | [8] | (4.2) | (4.2) | (1.1) | |||||
Total Assets | [8] | (26.3) | (26.3) | (12.5) | |||||
Current Risk Management Liabilities | [8] | (20.2) | (20.2) | (11.5) | |||||
Long-term Risk Management Liabilities | [8] | (3.8) | (3.8) | (1.1) | |||||
Total Liabilities | [8] | (24) | (24) | (12.6) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | (2.3) | (2.3) | 0.1 | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [8] | 0 | 0 | (0.2) | |||||
Long-term Risk Management Assets | [8] | 0 | 0 | 0 | |||||
Total Assets | [8] | 0 | 0 | (0.2) | |||||
Current Risk Management Liabilities | [8] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [8] | 0 | 0 | 0 | |||||
Total Liabilities | [8] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | 0 | 0 | (0.2) | |||||
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 | [8] | (0.4) | (0.4) | (0.1) | |||||
Long-term Risk Management Assets | [8] | 0 | 0 | 0 | |||||
Total Assets | [8] | (0.4) | (0.4) | (0.1) | |||||
Current Risk Management Liabilities | [8] | (0.4) | (0.4) | 0 | |||||
Long-term Risk Management Liabilities | [8] | 0 | 0 | 0 | |||||
Total Liabilities | [8] | (0.4) | (0.4) | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | 0 | 0 | (0.1) | |||||
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [8] | (0.4) | (0.4) | (0.2) | |||||
Long-term Risk Management Assets | [8] | 0 | 0 | 0 | |||||
Total Assets | [8] | (0.4) | (0.4) | (0.2) | |||||
Current Risk Management Liabilities | [8] | (0.4) | (0.4) | (0.1) | |||||
Long-term Risk Management Liabilities | [8] | 0 | 0 | 0 | |||||
Total Liabilities | [8] | (0.4) | (0.4) | (0.1) | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [8] | 0 | 0 | (0.1) | |||||
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] | |||||||||
Fair Value of Derivative Instruments | |||||||||
Current Risk Management Assets | [9] | 170.5 | 170.5 | 94.5 | |||||
Long-term Risk Management Assets | [9] | 285.6 | 285.6 | 289.1 | |||||
Total Assets | [9] | 456.1 | 456.1 | 383.6 | |||||
Current Risk Management Liabilities | [9] | 61.7 | 61.7 | 53.4 | |||||
Long-term Risk Management Liabilities | [9] | 310.6 | 310.6 | 316.2 | |||||
Total Liabilities | [9] | 372.3 | 372.3 | 369.6 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 83.8 | 83.8 | 14 | |||||
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 | [9] | 41.6 | 41.6 | 2.6 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 41.6 | 41.6 | 2.6 | |||||
Current Risk Management Liabilities | [9] | 0.4 | 0.4 | 0.3 | |||||
Long-term Risk Management Liabilities | [9] | 0.4 | 0.4 | 0.9 | |||||
Total Liabilities | [9] | 0.8 | 0.8 | 1.2 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 40.8 | 40.8 | 1.4 | |||||
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 | [9] | 15.8 | 15.8 | 3.5 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 15.8 | 15.8 | 3.5 | |||||
Current Risk Management Liabilities | [9] | 0.9 | 0.9 | 0.3 | |||||
Long-term Risk Management Liabilities | [9] | 0.2 | 0.2 | 0.8 | |||||
Total Liabilities | [9] | 1.1 | 1.1 | 1.1 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 14.7 | 14.7 | 2.4 | |||||
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 | [9] | 0 | 0 | 0.2 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 0 | 0 | 0.2 | |||||
Current Risk Management Liabilities | [9] | 7.1 | 7.1 | 5.9 | |||||
Long-term Risk Management Liabilities | [9] | 123.5 | 123.5 | 113.1 | |||||
Total Liabilities | [9] | 130.6 | 130.6 | 119 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | (130.6) | (130.6) | (118.8) | |||||
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 | [9] | 9.5 | 9.5 | 0.8 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 9.5 | 9.5 | 0.8 | |||||
Current Risk Management Liabilities | [9] | 0 | 0 | 0 | |||||
Long-term Risk Management Liabilities | [9] | 0 | 0 | 0 | |||||
Total Liabilities | [9] | 0 | 0 | 0 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | 9.5 | 9.5 | 0.8 | |||||
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 | [9] | 12.5 | 12.5 | 0.9 | |||||
Long-term Risk Management Assets | [9] | 0 | 0 | 0 | |||||
Total Assets | [9] | 12.5 | 12.5 | 0.9 | |||||
Current Risk Management Liabilities | [9] | 0.5 | 0.5 | 0.3 | |||||
Long-term Risk Management Liabilities | [9] | 0 | 0 | 0 | |||||
Total Liabilities | [9] | 0.5 | 0.5 | 0.3 | |||||
Total MTM Derivative Contract Net Assets (Liabilities) | [9] | $ 12 | $ 12 | $ 0.6 | |||||
Power [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 472.7 | 472.7 | 348 | ||||||
Power [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 91.5 | 91.5 | 51.9 | ||||||
Power [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 54.6 | 54.6 | 19.9 | ||||||
Power [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 10.7 | 10.7 | 11.2 | ||||||
Power [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 30.5 | 30.5 | 11.9 | ||||||
Power [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MWh | 36.4 | 36.4 | 14.2 | ||||||
Coal [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 1 | 1 | 1.5 | ||||||
Coal [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0 | 0 | 0 | ||||||
Coal [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0.5 | 0.5 | 0.5 | ||||||
Coal [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0 | 0 | 0 | ||||||
Coal [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0 | 0 | 0 | ||||||
Coal [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Mass Notional Amount | T | 0.5 | 0.5 | 1 | ||||||
Natural Gas [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 26.6 | 26.6 | 32.8 | ||||||
Natural Gas [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 1.9 | 1.9 | 0 | ||||||
Natural Gas [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 1.1 | 1.1 | 0 | ||||||
Natural Gas [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Natural Gas [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Natural Gas [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Energy Notional Amount | MMBTU | 0 | 0 | 0 | ||||||
Heating Oil and Gasoline [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 7.4 | 7.4 | 7.4 | ||||||
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1.4 | 1.4 | 1.4 | ||||||
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 0.7 | 0.7 | 0.7 | ||||||
Heating Oil and Gasoline [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 1.7 | 1.7 | 1.6 | ||||||
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 0.7 | 0.7 | 0.8 | ||||||
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Volume Notional Amount | gal | 0.9 | 0.9 | 0.9 | ||||||
Interest Rate Contract [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | $ 62 | $ 62 | $ 75.2 | ||||||
Interest Rate Contract [Member] | Appalachian Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0.1 | ||||||
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0.1 | ||||||
Interest Rate Contract [Member] | Ohio Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | 0 | ||||||
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member] | |||||||||
Commodity: | |||||||||
Derivative, Notional Amount | 0 | 0 | $ 0 | ||||||
Vertically Integrated Utilities Revenues [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0.6 | 0.1 | 6.1 | 0.7 | |||||
Vertically Integrated Utilities Revenues [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Vertically Integrated Utilities 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 | 0 | 0 | 0 | 0 | |||||
Vertically Integrated Utilities 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 | 0 | 0 | 0 | |||||
Vertically Integrated Utilities 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 | 0 | 0 | 0 | 0 | |||||
Vertically Integrated Utilities 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 | 0 | 0 | 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 | 10.3 | 21.1 | 20.8 | 40.9 | |||||
Generation and Marketing Revenues [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Generation and Marketing 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 | 0 | 0 | 0 | 0 | |||||
Generation and Marketing 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 | 0 | 0 | 0 | |||||
Generation and Marketing 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 | 0 | 0 | 0 | 0 | |||||
Generation and Marketing 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 | 0 | 0 | 0 | 0 | |||||
Electric Generation, Transmission and Distribution Revenues [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
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 | (0.1) | (1) | 0.3 | (1.8) | |||||
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 | 0.5 | 0.9 | 5.7 | 2.5 | |||||
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 | 0 | 0 | 0 | |||||
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 | 0 | 0 | 0 | 0 | |||||
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 | 0 | 0 | 0.1 | 0 | |||||
Sales to AEP Affiliates [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] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1 | 2.1 | |||||||
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 | 1.8 | 5.8 | |||||||
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 | 0 | 0 | |||||||
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | |||||||
Purchased Electricity for Resale [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 1.5 | 1.3 | 3.9 | 3.4 | |||||
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0.5 | 0.5 | 1.3 | 1.9 | |||||
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0.2 | 0 | 0.3 | 0.1 | |||||
Purchased Electricity for Resale [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | 0 | |||||
Other Operation Expense [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0.2 | (0.2) | 0.4 | (0.9) | |||||
Other Operation Expense [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Other Operation Expense [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Other Operation Expense [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | (0.1) | 0 | (0.2) | |||||
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Other Operation Expense [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 | (0.1) | 0 | (0.2) | |||||
Maintenance Expense [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0.1 | (0.4) | 0.3 | (1.2) | |||||
Maintenance Expense [Member] | Appalachian Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.2) | |||||
Maintenance Expense [Member] | Indiana Michigan Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Maintenance Expense [Member] | Ohio Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | (0.1) | 0 | (0.2) | |||||
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Maintenance Expense [Member] | Southwestern Electric Power Co [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | 0 | 0 | 0 | (0.1) | |||||
Regulatory Assets [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [10] | (3.1) | (14.3) | (18) | (28.4) | ||||
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 | [10] | 5.7 | (12.6) | (0.1) | (12.4) | ||||
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 | [10] | 0 | 1.1 | (0.2) | 1.4 | ||||
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 | [10] | (8.6) | (5.6) | (17.2) | (20.5) | ||||
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 | [10] | 0 | 0.3 | 0 | 0.3 | ||||
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 | [10] | 0 | 2.6 | (0.2) | 2.7 | ||||
Regulatory Liabilities [Member] | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | |||||||||
Amount of Gain (Loss) Recognized on Risk Management Contracts | [10] | 41 | 17.1 | 66.2 | 29.3 | ||||
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 | [10] | 13.6 | 6.4 | 24.5 | 22.3 | ||||
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 | [10] | 6.4 | 1.8 | 13.2 | 5.7 | ||||
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 | [10] | 0 | 0 | 0 | (15.2) | ||||
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 | [10] | 8.7 | 2.9 | 11.1 | 2.4 | ||||
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 | [10] | $ 10.4 | $ 6.5 | $ 15 | $ 11 | ||||
[1] | Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contacts. | ||||||||
[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 June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[4] | The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||
[5] | Substantially comprised of power contracts for the Registrant Subsidiaries. | ||||||||
[6] | Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. | ||||||||
[7] | Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” | ||||||||
[8] | Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” | ||||||||
[9] | There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. | ||||||||
[10] | Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. |
Fair Value Long-term Debt, Othe
Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | |||||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | $ 19,551.9 | $ 19,551.9 | $ 20,256.4 | ||||
Long Term Debt, Fair Value | 21,857.2 | 21,857.2 | |||||
Other Temporary Investments | |||||||
Cost | 301.9 | 301.9 | 318.8 | ||||
Gross Unrealized Gains | 16.4 | 16.4 | 13.9 | ||||
Gross Unrealized Losses | (0.7) | (0.7) | (1) | ||||
Fair Value | 317.6 | 317.6 | 331.7 | ||||
Debt and Equity Securities Within Other Temporary Investments | |||||||
Proceeds from Investment Sales | 0 | $ 0 | 0 | $ 0 | |||
Purchases of Investments | 0.5 | 0.6 | 1 | 1 | |||
Gross Realized Gains on Investment Sales | 0 | 0 | 0 | 0 | |||
Gross Realized Losses on Investment Sales | 0 | 0 | 0 | 0 | |||
Nuclear Trust Fund Investments | |||||||
Fair Value | 2,382 | 2,382 | 2,256.2 | ||||
Gross Unrealized Gains | 772.3 | 772.3 | 707.7 | ||||
Other-Than-Temporary Impairments | (382.6) | (382.6) | (87.2) | ||||
Securities Activity Within Decommissioning and SNF Trusts | |||||||
Proceeds from Investment Sales | 801.2 | 639.3 | 1,289.1 | 1,777 | |||
Purchases of Investments | 811.7 | 644.8 | 1,317.2 | 1,796.4 | |||
Gross Realized Gains on Investment Sales | 177 | 12.2 | 188.3 | 28 | |||
Gross Realized Losses on Investment Sales | 132.1 | 7.9 | 140.2 | 15.7 | |||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 2,382 | 2,382 | 2,256.2 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 21,857.2 | 21,857.2 | |||||
Adjusted Cost of Debt Securities | 1,000 | 1,000 | 938 | ||||
Adjusted Cost of Domestic Equity Securities | 578 | 578 | 592 | ||||
Lawrenceburg Plant [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Long Term Debt, Fair Value | 172 | ||||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 172 | ||||||
Includes Debt Included In Liabilities Held For Sale [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 19,551.9 | 19,551.9 | 20,391.2 | [1] | |||
Long Term Debt, Fair Value | [1] | 22,211.9 | |||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | [1] | 22,211.9 | |||||
AEP Transmission Co [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 1,931.4 | 1,931.4 | 1,932 | ||||
Long Term Debt, Fair Value | 2,105.2 | 2,105.2 | 1,984.3 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 2,105.2 | 2,105.2 | 1,984.3 | ||||
Appalachian Power Co [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 3,990.5 | 3,990.5 | 4,033.9 | ||||
Long Term Debt, Fair Value | 4,734.5 | 4,734.5 | 4,613.2 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 4,734.5 | 4,734.5 | 4,613.2 | ||||
Indiana Michigan Power Co [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 2,691.4 | 2,691.4 | 2,471.4 | ||||
Long Term Debt, Fair Value | 2,937.7 | 2,937.7 | 2,661.6 | ||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 2,382 | 2,382 | 2,256.2 | ||||
Gross Unrealized Gains | 772.3 | 772.3 | 707.7 | ||||
Other-Than-Temporary Impairments | (382.6) | (382.6) | (87.2) | ||||
Securities Activity Within Decommissioning and SNF Trusts | |||||||
Proceeds from Investment Sales | 801.2 | 639.3 | 1,289.1 | 1,777 | |||
Purchases of Investments | 811.7 | 644.8 | 1,317.2 | 1,796.4 | |||
Gross Realized Gains on Investment Sales | 177 | 12.2 | 188.3 | 28 | |||
Gross Realized Losses on Investment Sales | 132.1 | $ 7.9 | 140.2 | $ 15.7 | |||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 2,382 | 2,382 | 2,256.2 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 2,937.7 | 2,937.7 | 2,661.6 | ||||
Adjusted Cost of Debt Securities | 1,000 | 1,000 | 938 | ||||
Adjusted Cost of Domestic Equity Securities | 578 | 578 | 592 | ||||
Ohio Power Co [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 1,742.5 | 1,742.5 | 1,763.9 | ||||
Long Term Debt, Fair Value | 2,098.7 | 2,098.7 | 2,092.5 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 2,098.7 | 2,098.7 | 2,092.5 | ||||
Public Service Co Of Oklahoma [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 1,286.3 | 1,286.3 | 1,286 | ||||
Long Term Debt, Fair Value | 1,451.5 | 1,451.5 | 1,419 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 1,451.5 | 1,451.5 | 1,419 | ||||
Southwestern Electric Power Co [Member] | |||||||
Book Values and Fair Values of Long - term Debt | |||||||
Total Long-term Debt Outstanding | 2,442.7 | 2,442.7 | 2,679.1 | ||||
Long Term Debt, Fair Value | 2,634.8 | 2,634.8 | 2,814.3 | ||||
Fair Value Measurements (Textuals) | |||||||
Long Term Debt, Fair Value | 2,634.8 | 2,634.8 | 2,814.3 | ||||
Cash [Member] | |||||||
Other Temporary Investments | |||||||
Cost | [2] | 193.7 | 193.7 | 211.7 | |||
Gross Unrealized Gains | [2] | 0 | 0 | 0 | |||
Gross Unrealized Losses | [2] | 0 | 0 | 0 | |||
Fair Value | [2],[3] | 193.7 | 193.7 | 211.7 | |||
Fixed Income Funds [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 1,049.8 | 1,049.8 | 967.4 | ||||
Gross Unrealized Gains | 36.8 | 36.8 | 29.8 | ||||
Other-Than-Temporary Impairments | (306.5) | (306.5) | (7.6) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 1,049.8 | 1,049.8 | 967.4 | ||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 1,049.8 | 1,049.8 | 967.4 | ||||
Gross Unrealized Gains | 36.8 | 36.8 | 29.8 | ||||
Other-Than-Temporary Impairments | (306.5) | (306.5) | (7.6) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 1,049.8 | 1,049.8 | 967.4 | ||||
Mutual Funds Fixed Income [Member] | |||||||
Other Temporary Investments | |||||||
Cost | [4] | 93.5 | 93.5 | 92.7 | |||
Gross Unrealized Gains | [4] | 0 | 0 | 0 | |||
Gross Unrealized Losses | [4] | (0.7) | (0.7) | (1) | |||
Fair Value | [4] | 92.8 | 92.8 | 91.7 | |||
Domestic [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | [5] | 1,313 | 1,313 | 1,270.1 | |||
Gross Unrealized Gains | 735.5 | 735.5 | 677.9 | ||||
Other-Than-Temporary Impairments | (76.1) | (76.1) | (79.6) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | [5] | 1,313 | 1,313 | 1,270.1 | |||
Domestic [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | [5] | 1,313 | 1,313 | 1,270.1 | |||
Gross Unrealized Gains | 735.5 | 735.5 | 677.9 | ||||
Other-Than-Temporary Impairments | (76.1) | (76.1) | (79.6) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | [5] | 1,313 | 1,313 | 1,270.1 | |||
Mutual Funds Equity [Member] | |||||||
Other Temporary Investments | |||||||
Cost | 14.7 | 14.7 | 14.4 | ||||
Gross Unrealized Gains | 16.4 | 16.4 | 13.9 | ||||
Gross Unrealized Losses | 0 | 0 | 0 | ||||
Fair Value | [5] | 31.1 | 31.1 | 28.3 | |||
Cash and Cash Equivalents [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | [6] | 19.2 | 19.2 | 18.7 | |||
Gross Unrealized Gains | 0 | 0 | 0 | ||||
Other-Than-Temporary Impairments | 0 | 0 | 0 | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | [6] | 19.2 | 19.2 | 18.7 | |||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | [6] | 19.2 | 19.2 | 18.7 | |||
Gross Unrealized Gains | 0 | 0 | 0 | ||||
Other-Than-Temporary Impairments | 0 | 0 | 0 | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | [6] | 19.2 | 19.2 | 18.7 | |||
US Government Agencies Debt Securities [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 904.1 | 904.1 | 785.4 | ||||
Gross Unrealized Gains | 33.5 | 33.5 | 27.1 | ||||
Other-Than-Temporary Impairments | (304.1) | (304.1) | (5.5) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 904.1 | 904.1 | 785.4 | ||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 904.1 | 904.1 | 785.4 | ||||
Gross Unrealized Gains | 33.5 | 33.5 | 27.1 | ||||
Other-Than-Temporary Impairments | (304.1) | (304.1) | (5.5) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 904.1 | 904.1 | 785.4 | ||||
Corporate Debt [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 59 | 59 | 60.9 | ||||
Gross Unrealized Gains | 3.3 | 3.3 | 2.3 | ||||
Other-Than-Temporary Impairments | (1.2) | (1.2) | (1.4) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 59 | 59 | 60.9 | ||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 59 | 59 | 60.9 | ||||
Gross Unrealized Gains | 3.3 | 3.3 | 2.3 | ||||
Other-Than-Temporary Impairments | (1.2) | (1.2) | (1.4) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 59 | 59 | 60.9 | ||||
State and Local Jurisdiction [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 86.7 | 86.7 | 121.1 | ||||
Gross Unrealized Gains | 0 | 0 | 0.4 | ||||
Other-Than-Temporary Impairments | (1.2) | (1.2) | (0.7) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 86.7 | 86.7 | 121.1 | ||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 86.7 | 86.7 | 121.1 | ||||
Gross Unrealized Gains | 0 | 0 | 0.4 | ||||
Other-Than-Temporary Impairments | (1.2) | (1.2) | (0.7) | ||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 86.7 | 86.7 | $ 121.1 | ||||
Within One Year [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 243.9 | 243.9 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 243.9 | 243.9 | |||||
Within One Year [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 243.9 | 243.9 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 243.9 | 243.9 | |||||
One Year To Five Year [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 398.9 | 398.9 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 398.9 | 398.9 | |||||
One Year To Five Year [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 398.9 | 398.9 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 398.9 | 398.9 | |||||
Five Year To Ten Year [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 160.6 | 160.6 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 160.6 | 160.6 | |||||
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 160.6 | 160.6 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 160.6 | 160.6 | |||||
After Ten Year [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 246.4 | 246.4 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | 246.4 | 246.4 | |||||
After Ten Year [Member] | Indiana Michigan Power Co [Member] | |||||||
Nuclear Trust Fund Investments | |||||||
Fair Value | 246.4 | 246.4 | |||||
Contractual Maturities, Fair Value of Debt Securities | |||||||
Contractual Maturities, Fair Value of Debt Securities | $ 246.4 | $ 246.4 | |||||
[1] | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information. | ||||||
[2] | Primarily represents amounts held for the repayment of debt. | ||||||
[3] | 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. | ||||||
[4] | Primarily short and intermediate maturities which may be sold and do not contain maturity dates. | ||||||
[5] | Amounts represent publicly traded equity securities and equity-based mutual funds. | ||||||
[6] | Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. |
Fair Value Assets and Liabiliti
Fair Value Assets and Liabilities (Details) $ in Millions | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||||||
Jun. 30, 2017USD ($)$ / MWh | Jun. 30, 2016USD ($) | Jun. 30, 2017USD ($)$ / MWh | Jun. 30, 2016USD ($) | Dec. 31, 2016USD ($)$ / MWh | |||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | $ 172.4 | $ 172.4 | $ 210.5 | |||||||
Other Temporary Investments | 317.6 | 317.6 | 331.7 | ||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 456.1 | 456.1 | 383.6 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 2,382 | 2,382 | 2,256.2 | ||||||||
Total Assets | 3,328.1 | 3,328.1 | 3,182 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 372.3 | 372.3 | 369.6 | ||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | (18.5) | $ 141.3 | 2.5 | $ 146.9 | 146.9 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 17.1 | 16 | 32 | 41.3 | ||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 8.7 | 2.9 | 25.2 | 24.8 | ||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 12.1 | 17.3 | (5.1) | 18.8 | |||||||
Settlements | (16.1) | (17.5) | (44.3) | (60) | |||||||
Transfers into Level 3 | [4],[5] | 6.2 | 8.2 | 10.7 | 8.1 | ||||||
Transfers out of Level 3 | [5] | 1.1 | (9.4) | 10.9 | |||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | 78.9 | (18.9) | 75.7 | (41.5) | ||||||
Ending Balance | 87.3 | 149.3 | $ 87.3 | 149.3 | $ 2.5 | ||||||
Low [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 0.19% | 0.35% | ||||||||
High [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 7.83% | 8.24% | ||||||||
Weighted Average [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 2.88% | 3.91% | ||||||||
Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 172.4 | $ 172.4 | $ 201.8 | |||||||
Other Temporary Investments | 36.1 | 36.1 | 32.8 | ||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | (240.1) | (240.1) | (213) | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 9.6 | 9.6 | 11.4 | ||||||||
Total Assets | (22) | (22) | 33 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | (254.9) | (254.9) | (212.7) | ||||||||
Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 8.7 | |||||||
Other Temporary Investments | 280.2 | 280.2 | 293.8 | ||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 1.5 | 1.5 | 6 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,322.6 | 1,322.6 | 1,277.4 | ||||||||
Total Assets | 1,604.3 | 1,604.3 | 1,585.9 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 4.3 | 4.3 | 8.2 | ||||||||
Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Other Temporary Investments | 1.3 | 1.3 | 5.1 | ||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 402.6 | 402.6 | 396.7 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Total Assets | 1,453.7 | 1,453.7 | 1,369.2 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 418.1 | 418.1 | 382.7 | ||||||||
Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 292.1 | 292.1 | 193.9 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Total Assets | 292.1 | 292.1 | 193.9 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 204.8 | 204.8 | 191.4 | ||||||||
2017 [Member] | Level 1 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | (1) | (1) | |||||||||
2017 [Member] | Level 2 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 6 | 6 | 20 | ||||||||
2017 [Member] | Level 3 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 61 | 61 | 17 | ||||||||
2018 - 2020 [Member] | Level 1 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | (2) | (2) | (2) | ||||||||
2018 - 2020 [Member] | Level 2 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 5 | 5 | 4 | ||||||||
2018 - 2020 [Member] | Level 3 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 63 | 63 | 28 | ||||||||
2021 - 2022 [Member] | Level 2 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 3 | ||||||||||
2021 - 2022 [Member] | Level 3 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 15 | 15 | 11 | ||||||||
2023 - 2032 [Member] | Level 2 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | 1 | 1 | 1 | ||||||||
2023 - 2032 [Member] | Level 3 [Member] | |||||||||||
Fair Value Measurements 1 (Textuals) | |||||||||||
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities | (27) | (27) | (31) | ||||||||
Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 447.3 | [9] | 447.3 | [9] | 372.4 | [10] | ||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 311.6 | [9] | 311.6 | [9] | 321.5 | [10] | ||||
Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | (233.9) | [9] | (233.9) | [9] | (205.7) | [10] | ||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | (248.7) | [9] | (248.7) | [9] | (205.4) | [10] | ||||
Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 1.5 | [9] | 1.5 | [9] | 6 | [10] | ||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 4.3 | [9] | 4.3 | [9] | 8.2 | [10] | ||||
Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 388.7 | [9] | 388.7 | [9] | 379.9 | [10] | ||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 377.1 | [9] | 377.1 | [9] | 352 | [10] | ||||
Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 291 | [9] | 291 | [9] | 192.2 | [10] | ||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 178.9 | [9] | 178.9 | [9] | 166.7 | [10] | ||||
Energy Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 201 | 201 | 183.8 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 200.8 | $ 200.8 | $ 187.1 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 10.98 | 10.98 | 6.51 | |||||||
Forward Price Range High | $ / MWh | [11] | 99.44 | 99.44 | 86.59 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 38.28 | 38.28 | 39.4 | |||||||
FTRs [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | $ 91.1 | $ 91.1 | $ 10.1 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 4 | $ 4 | $ 4.3 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | (6.70) | (6.70) | (7.99) | |||||||
Forward Price Range High | $ / MWh | [11] | 7.35 | 7.35 | 8.91 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 0.36 | 0.36 | 0.86 | |||||||
Commodity Hedges [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | $ 4 | $ 4 | $ 11.2 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 59.2 | 59.2 | 46.7 | |||||||
Commodity Hedges [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | (6.2) | (6.2) | (7.3) | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | (6.2) | (6.2) | (7.3) | |||||||
Commodity Hedges [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 0 | 0 | 0 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 0 | 0 | 0 | |||||||
Commodity Hedges [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 9.1 | 9.1 | 16.8 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 39.5 | 39.5 | 29.3 | |||||||
Commodity Hedges [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8] | 1.1 | 1.1 | 1.7 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8] | 25.9 | 25.9 | 24.7 | |||||||
Interest Rate and Foreign Currency [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 4.8 | 4.8 | |||||||||
Interest Rate and Foreign Currency [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0 | 0 | |||||||||
Interest Rate and Foreign Currency [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0 | 0 | |||||||||
Interest Rate and Foreign Currency [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 4.8 | 4.8 | |||||||||
Interest Rate and Foreign Currency [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0 | 0 | |||||||||
Fair Value Hedges [Member] | |||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 1.5 | 1.5 | 1.4 | ||||||||
Fair Value Hedges [Member] | Other [Member] | |||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||||
Fair Value Hedges [Member] | Level 1 [Member] | |||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||||
Fair Value Hedges [Member] | Level 2 [Member] | |||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 1.5 | 1.5 | 1.4 | ||||||||
Fair Value Hedges [Member] | Level 3 [Member] | |||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 0 | 0 | 0 | ||||||||
Appalachian Power Co [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 15.5 | 15.5 | 15.9 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 57.1 | 57.1 | 18.5 | ||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | (5.8) | 2.6 | [12] | 1.4 | 11.7 | [12] | 11.7 | [12] | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 12.2 | 8.6 | [12] | 16.9 | 25.1 | [12] | ||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 0 | 0 | [12] | 0 | 0 | [12] | ||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | [12] | 0 | 0 | [12] | |||||
Settlements | (6.4) | (6.8) | [12] | (18.6) | (34.5) | [12] | |||||
Transfers into Level 3 | [4],[5] | 0 | 0 | [12] | 0 | 0 | [12] | ||||
Transfers out of Level 3 | [5] | 0 | 0 | 0.1 | [12] | ||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | 41.3 | (17.3) | [12] | 41.6 | (15.3) | [12] | ||||
Ending Balance | 41.3 | (12.9) | [12] | 41.3 | (12.9) | [12] | 1.4 | ||||
Appalachian Power Co [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0.1 | 0.1 | 0.1 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | (33.1) | (33.1) | (21.7) | ||||||||
Appalachian Power Co [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 15.4 | 15.4 | 15.8 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 15.4 | 15.4 | 15.8 | ||||||||
Appalachian Power Co [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 33.2 | 33.2 | 20.5 | ||||||||
Appalachian Power Co [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 41.6 | 41.6 | 3.9 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 41.6 | 41.6 | 3.9 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 0.3 | 0.3 | 2.5 | ||||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 41.6 | 41.6 | 2.6 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.8 | 0.8 | 1.2 | |||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | (33.2) | (33.2) | (21.8) | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | (31.2) | (31.2) | (22) | |||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | 0 | |||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 33.2 | 33.2 | 20.5 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 31.7 | 31.7 | 20.7 | |||||||
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 41.6 | 41.6 | 3.9 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.3 | 0.3 | 2.5 | |||||||
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0.8 | 0.8 | 0.4 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 0.1 | $ 0.1 | $ 0.4 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 17.85 | 17.85 | 19.68 | |||||||
Forward Price Range High | $ / MWh | [11] | 46.97 | 46.97 | 48.55 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 33.62 | 33.62 | 36.34 | |||||||
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | $ 40.8 | $ 40.8 | $ 3.5 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 0.2 | $ 0.2 | $ 2.1 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 0.1 | 0.1 | (0.23) | |||||||
Forward Price Range High | $ / MWh | [11] | 7.35 | 7.35 | 8.91 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 1.23 | 1.23 | 2.37 | |||||||
Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | $ 2,382 | $ 2,382 | $ 2,256.2 | ||||||||
Total Assets | 2,397.8 | 2,397.8 | 2,259.7 | ||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | 2 | 3.7 | [12] | 2.8 | 4.3 | [12] | 4.3 | [12] | |||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 0.6 | 3.5 | [12] | 3.9 | 6.7 | [12] | ||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 0 | 0 | [12] | 0 | 0 | [12] | ||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | [12] | 0 | 0 | [12] | |||||
Settlements | (2.7) | (4.6) | [12] | (6.9) | (9.2) | [12] | |||||
Transfers into Level 3 | [4],[5] | 0 | 0 | [12] | 0 | 0 | [12] | ||||
Transfers out of Level 3 | [5] | 0 | 0 | 0.1 | [12] | ||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | 15.6 | 0.9 | [12] | 15.7 | 1.6 | [12] | ||||
Ending Balance | 15.5 | 3.5 | [12] | 15.5 | 3.5 | [12] | 2.8 | ||||
Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 9.6 | 9.6 | 11.4 | ||||||||
Total Assets | (14.2) | (14.2) | (0.9) | ||||||||
Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,322.6 | 1,322.6 | 1,277.4 | ||||||||
Total Assets | 1,322.6 | 1,322.6 | 1,277.4 | ||||||||
Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Total Assets | 1,072.4 | 1,072.4 | 980.2 | ||||||||
Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 17 | 17 | 3 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Total Assets | 17 | 17 | 3 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 1.5 | 1.5 | 0.2 | ||||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 15.8 | 15.8 | 3.5 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 1.1 | 1.1 | 1.1 | |||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | (23.8) | (23.8) | (12.3) | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | (21.5) | (21.5) | (12.4) | |||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | 0 | |||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 22.6 | 22.6 | 12.8 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 21.1 | 21.1 | 13.3 | |||||||
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 17 | 17 | 3 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 1.5 | 1.5 | 0.2 | |||||||
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0.6 | 0.6 | 0.3 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 0.1 | $ 0.1 | $ 0.2 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 17.85 | 17.85 | 19.68 | |||||||
Forward Price Range High | $ / MWh | [11] | 46.97 | 46.97 | 48.55 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 33.62 | 33.62 | 36.34 | |||||||
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | $ 16.4 | $ 16.4 | $ 2.7 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 1.4 | $ 1.4 | $ 0 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 0.01 | 0.01 | (7.9) | |||||||
Forward Price Range High | $ / MWh | [11] | 6.93 | 6.93 | 8.91 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 0.79 | 0.79 | 1.32 | |||||||
Ohio Power Co [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | $ 27.3 | $ 27.3 | $ 27.2 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 27.4 | ||||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | (124.6) | (10.9) | (119) | 15.9 | 15.9 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | (0.1) | (0.2) | (4.3) | (1.4) | ||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 0 | 0 | 0 | 0 | ||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | 0 | 0 | |||||||
Settlements | 1.9 | 1.7 | 4.1 | 3.1 | |||||||
Transfers into Level 3 | [4],[5] | 0 | 0 | 0 | 0 | ||||||
Transfers out of Level 3 | [5] | 0 | 0 | 0 | |||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | (7.7) | (5.2) | (11.3) | (32.2) | ||||||
Ending Balance | (130.5) | (14.6) | $ (130.5) | (14.6) | $ (119) | ||||||
Ohio Power Co [Member] | Low [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 0.19% | 0.47% | ||||||||
Ohio Power Co [Member] | High [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 3.02% | 3.40% | ||||||||
Ohio Power Co [Member] | Weighted Average [Member] | |||||||||||
Level 3 Quantitative Information | |||||||||||
Counterparty Credit Risk | [7] | 2.14% | 2.72% | ||||||||
Ohio Power Co [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 27.3 | $ 27.3 | $ 27.2 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 27 | ||||||||||
Ohio Power Co [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 0 | ||||||||||
Ohio Power Co [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 0.4 | ||||||||||
Ohio Power Co [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0 | 0 | 0 | ||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 0 | ||||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | 130.5 | 130.5 | 119 | ||||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0.2 | |||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 130.6 | 130.6 | 119 | |||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | (0.2) | |||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | 0 | |||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | |||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | 0 | |||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0.4 | |||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.1 | 0.1 | 0 | |||||||
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | |||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 130.5 | 130.5 | 119 | |||||||
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 0 | 0 | 0 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 130.5 | $ 130.5 | $ 119 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | 27.17 | 27.17 | 30.14 | |||||||
Forward Price Range High | $ / MWh | [11] | 66.88 | 66.88 | 71.85 | |||||||
Weighted Average Market Price | $ / MWh | [11] | 43.36 | 43.36 | 47.45 | |||||||
Public Service Co Of Oklahoma [Member] | |||||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | $ 0.4 | 0.6 | $ 0.7 | 0.6 | $ 0.6 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 0.8 | (0.4) | 3.1 | (1) | ||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 0 | 0 | 0 | 0 | ||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | 0 | 0 | |||||||
Settlements | (1.3) | (0.2) | (3.8) | 0.4 | |||||||
Transfers into Level 3 | [4],[5] | 0 | 0 | 0 | 0 | ||||||
Transfers out of Level 3 | [5] | 0 | 0 | 0 | |||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | 9.6 | 1.1 | 9.5 | 1.1 | ||||||
Ending Balance | 9.5 | 1.1 | 9.5 | 1.1 | 0.7 | ||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 9.5 | 9.5 | 0.8 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | ||||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | (0.4) | (0.4) | (0.1) | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | (0.4) | (0.4) | ||||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | ||||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0.2 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | ||||||||
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 9.9 | 9.9 | 0.7 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.4 | 0.4 | ||||||||
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 9.9 | 9.9 | 0.7 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 0.4 | $ 0.4 | $ 0 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | (6.7) | (6.7) | (7.99) | |||||||
Forward Price Range High | $ / MWh | [11] | 0.13 | 0.13 | 1.03 | |||||||
Weighted Average Market Price | $ / MWh | [11] | (0.67) | (0.67) | (0.36) | |||||||
Southwestern Electric Power Co [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | $ 1.7 | $ 1.7 | $ 10.3 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 14.2 | 14.2 | 11.2 | ||||||||
Changes in the Fair Value of Net Trading Derivatives and other investments | |||||||||||
Beginning Balance | 0.5 | 0.7 | 0.7 | 0.8 | 0.8 | ||||||
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) | [2],[3] | 1.4 | 2.7 | 6 | 7.7 | ||||||
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date | [2] | 0 | 0 | 0 | 0 | ||||||
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income | 0 | 0 | 0 | 0 | |||||||
Settlements | (1.9) | (3.5) | (6.8) | (8.4) | |||||||
Transfers into Level 3 | [4],[5] | 0 | 0 | 0 | 0 | ||||||
Transfers out of Level 3 | [5] | 0 | 0 | 0 | |||||||
Changes in Fair Value Allocated to Regulated Jurisdiction | [6] | 12.4 | 1.5 | 12.5 | 1.3 | ||||||
Ending Balance | 12.4 | $ 1.4 | 12.4 | $ 1.4 | 0.7 | ||||||
Southwestern Electric Power Co [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 1.7 | 1.7 | 1.6 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 1.3 | 1.3 | 1.4 | ||||||||
Southwestern Electric Power Co [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 8.7 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 0 | 0 | 8.7 | ||||||||
Southwestern Electric Power Co [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 0 | 0 | 0.3 | ||||||||
Southwestern Electric Power Co [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Cash and Cash Equivalents | [1] | 0 | 0 | 0 | |||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Total Assets | 12.9 | 12.9 | 0.8 | ||||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 12.5 | 12.5 | 0.9 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.5 | 0.5 | 0.3 | |||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | (0.4) | (0.4) | (0.2) | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | (0.4) | (0.4) | (0.1) | |||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0 | 0 | 0 | |||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 0 | 0 | 0.3 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.4 | 0.4 | 0.3 | |||||||
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | [8],[13] | 12.9 | 12.9 | 0.8 | |||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | [8],[13] | 0.5 | 0.5 | 0.1 | |||||||
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member] | |||||||||||
Risk Management Assets | |||||||||||
Risk Management Assets | 12.9 | 12.9 | 0.8 | ||||||||
Liabilities, Fair Value Disclosure | |||||||||||
Risk Management Liabilities | $ 0.5 | $ 0.5 | $ 0.1 | ||||||||
Level 3 Quantitative Information | |||||||||||
Forward Price Range Low | $ / MWh | [11] | (6.7) | (6.7) | (7.99) | |||||||
Forward Price Range High | $ / MWh | [11] | 0.13 | 0.13 | 1.03 | |||||||
Weighted Average Market Price | $ / MWh | [11] | (0.67) | (0.67) | (0.36) | |||||||
Cash [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [1],[14] | $ 193.7 | $ 193.7 | $ 211.7 | |||||||
Cash [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [1] | 36.1 | 36.1 | 32.8 | |||||||
Cash [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [1] | 156.3 | 156.3 | 173.8 | |||||||
Cash [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [1] | 1.3 | 1.3 | 5.1 | |||||||
Cash [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [1] | 0 | 0 | 0 | |||||||
Fixed Income Funds [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Fixed Income Funds [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Fixed Income Funds [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Fixed Income Funds [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Fixed Income Funds [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 1,049.8 | 1,049.8 | 967.4 | ||||||||
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Mutual Funds Fixed Income [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [15] | 92.8 | 92.8 | 91.7 | |||||||
Mutual Funds Fixed Income [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||||
Mutual Funds Fixed Income [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | 92.8 | 92.8 | 91.7 | ||||||||
Mutual Funds Fixed Income [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||||
Mutual Funds Fixed Income [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | 0 | 0 | 0 | ||||||||
Mutual Funds Equity [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [16] | 31.1 | 31.1 | 28.3 | |||||||
Mutual Funds Equity [Member] | Other [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [16] | 0 | 0 | 0 | |||||||
Mutual Funds Equity [Member] | Level 1 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [16] | 31.1 | 31.1 | 28.3 | |||||||
Mutual Funds Equity [Member] | Level 2 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [16] | 0 | 0 | 0 | |||||||
Mutual Funds Equity [Member] | Level 3 [Member] | |||||||||||
Assets, Fair Value Disclosure | |||||||||||
Other Temporary Investments | [16] | 0 | 0 | 0 | |||||||
Cash and Cash Equivalents [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 19.2 | 19.2 | 18.7 | |||||||
Cash and Cash Equivalents [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 9.6 | 9.6 | 11.4 | |||||||
Cash and Cash Equivalents [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 9.6 | 9.6 | 7.3 | |||||||
Cash and Cash Equivalents [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 0 | 0 | 0 | |||||||
Cash and Cash Equivalents [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 0 | 0 | 0 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 19.2 | 19.2 | 18.7 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 9.6 | 9.6 | 11.4 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 9.6 | 9.6 | 7.3 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 0 | 0 | 0 | |||||||
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [17] | 0 | 0 | 0 | |||||||
US Government Agencies Debt Securities [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 904.1 | 904.1 | 785.4 | ||||||||
US Government Agencies Debt Securities [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
US Government Agencies Debt Securities [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
US Government Agencies Debt Securities [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 904.1 | 904.1 | 785.4 | ||||||||
US Government Agencies Debt Securities [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 904.1 | 904.1 | 785.4 | ||||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 904.1 | 904.1 | 785.4 | ||||||||
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 59 | 59 | 60.9 | ||||||||
Corporate Debt [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 59 | 59 | 60.9 | ||||||||
Corporate Debt [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 59 | 59 | 60.9 | ||||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 59 | 59 | 60.9 | ||||||||
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 86.7 | 86.7 | 121.1 | ||||||||
State and Local Jurisdiction [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 86.7 | 86.7 | 121.1 | ||||||||
State and Local Jurisdiction [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 86.7 | 86.7 | 121.1 | ||||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 86.7 | 86.7 | 121.1 | ||||||||
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | 0 | 0 | 0 | ||||||||
Domestic [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 1,313 | 1,313 | 1,270.1 | |||||||
Domestic [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 0 | 0 | 0 | |||||||
Domestic [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 1,313 | 1,313 | 1,270.1 | |||||||
Domestic [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 0 | 0 | 0 | |||||||
Domestic [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 0 | 0 | 0 | |||||||
Domestic [Member] | Indiana Michigan Power Co [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 1,313 | 1,313 | 1,270.1 | |||||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 0 | 0 | 0 | |||||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 1,313 | 1,313 | 1,270.1 | |||||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | 0 | 0 | 0 | |||||||
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member] | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | |||||||||||
Spent Nuclear Fuel and Decommissioning Trusts | [16] | $ 0 | $ 0 | $ 0 | |||||||
[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 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 existing assets or liabilities that were previously categorized as Level 2. | ||||||||||
[5] | Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. | ||||||||||
[6] | Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory liabilities/assets or accounts payable. | ||||||||||
[7] | Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. | ||||||||||
[8] | 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.’’ | ||||||||||
[9] | The June 30, 2017 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(1) million in 2017 and $(2) million in periods 2018-2020; Level 2 matures $6 million in 2017 and $5 million in periods 2018-2020 and $1 million in periods 2023-2032; Level 3 matures $61 million in 2017, $63 million in periods 2018-2020, $15 million in periods 2021-2022 and $(27) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||||
[10] | The December 31, 2016 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 periods 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. | ||||||||||
[11] | Represents market prices in dollars per MWh. | ||||||||||
[12] | Includes both affiliated and nonaffiliated transactions. | ||||||||||
[13] | Substantially comprised of power contracts for the Registrant Subsidiaries. | ||||||||||
[14] | Primarily represents amounts held for the repayment of debt. | ||||||||||
[15] | Primarily short and intermediate maturities which may be sold and do not contain maturity dates. | ||||||||||
[16] | Amounts represent publicly traded equity securities and equity-based mutual funds. | ||||||||||
[17] | Amounts in “Other’’ column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | |
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 34.60% | 24.30% | 36.50% | 28.80% |
Income Taxes (Textuals) [Abstract] | ||||
Pre July 1 2017 Illinois Corporate Income Tax Rate | 5.25% | |||
Effective July 1 2017 Illinois Corporate Income Tax Rate | 7.00% | |||
Illinois Replacement Tax | 2.50% | |||
Total Illinois Corporate Income Tax Rate | 7.75% | |||
Increased Total Illinois Corporate Income Tax Rate | 9.50% | |||
2011 Audit Issue Settlement [Member] | ||||
Valuation Allowance | $ 56 | $ 56 | ||
AEP Transmission Co [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 34.20% | 33.10% | 33.90% | 32.10% |
Appalachian Power Co [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 36.50% | 35.90% | 36.50% | 36.30% |
Income Taxes (Textuals) [Abstract] | ||||
Pre July 1 2017 Illinois Corporate Income Tax Rate | 5.25% | |||
Effective July 1 2017 Illinois Corporate Income Tax Rate | 7.00% | |||
Illinois Replacement Tax | 2.50% | |||
Total Illinois Corporate Income Tax Rate | 7.75% | |||
Increased Total Illinois Corporate Income Tax Rate | 9.50% | |||
Indiana Michigan Power Co [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 27.60% | 32.90% | 29.60% | 28.10% |
Income Taxes (Textuals) [Abstract] | ||||
Pre July 1 2017 Illinois Corporate Income Tax Rate | 5.25% | |||
Effective July 1 2017 Illinois Corporate Income Tax Rate | 7.00% | |||
Illinois Replacement Tax | 2.50% | |||
Total Illinois Corporate Income Tax Rate | 7.75% | |||
Increased Total Illinois Corporate Income Tax Rate | 9.50% | |||
Ohio Power Co [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 34.90% | 34.10% | 34.90% | 34.50% |
Public Service Co Of Oklahoma [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 37.60% | 36.20% | 37.60% | 35.50% |
Southwestern Electric Power Co [Member] | ||||
Federal Statutory Tax Rate | 35.00% | |||
Effective Income Tax Rate | 29.70% | 23.60% | 32.40% | 23.70% |
Financing Activities (Details)
Financing Activities (Details) - USD ($) $ in Millions | 1 Months Ended | 3 Months Ended | 6 Months Ended | |||||
Jul. 27, 2017 | Jun. 30, 2017 | Jun. 30, 2016 | Jun. 30, 2017 | Jun. 30, 2016 | Dec. 31, 2016 | |||
Long-term Debt | ||||||||
Senior Unsecured Notes | $ 14,728.9 | $ 14,728.9 | ||||||
Pollution Control Bonds | 1,611.1 | 1,611.1 | $ 1,725.1 | |||||
Notes Payable | 259.7 | 259.7 | 326.9 | |||||
Securitization Bonds | 1,555.8 | 1,555.8 | 1,705 | |||||
Spent Nuclear Fuel Obligation | [1] | 267.1 | 267.1 | 266.3 | ||||
Other Long-term Debt | 1,129.3 | 1,129.3 | 1,606.9 | |||||
Total Long-term Debt Outstanding | 19,551.9 | 19,551.9 | 20,256.4 | |||||
Long-term Debt Due Within One Year | 2,755 | 2,755 | 2,878 | |||||
Long-term Debt | 16,796.9 | 16,796.9 | 17,378.4 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | 1,061.1 | ||||||
Retirements and Principal Payments | 1,899.3 | $ 784.1 | ||||||
Short-term Debt: | ||||||||
Securitized Debt for Receivables | [3] | 519 | 519 | 673 | ||||
Commercial Paper | 1,324 | 1,324 | 1,040 | |||||
Notes Payable | 8.7 | 8.7 | 0 | |||||
Total Short-term Debt | $ 1,851.7 | $ 1,851.7 | $ 1,713 | |||||
Securitized Debt for Receivables | [3],[4] | 1.09% | 1.09% | 0.70% | ||||
Comparative Accounts Receivable Information | ||||||||
Effective Interest Rates on Securitization of Accounts Receivable | 1.17% | 0.63% | 1.09% | 0.61% | ||||
Net Uncollectible Accounts Receivable Written Off | $ 5.3 | $ 4.1 | $ 11.2 | $ 9.8 | ||||
Customer Accounts Receivable Managed Portfolio | ||||||||
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts | 921.7 | 921.7 | $ 945 | |||||
Total Principal Outstanding | 519 | 519 | 673 | |||||
Delinquent Securitized Accounts Receivable | 44.3 | 44.3 | 42.7 | |||||
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable | 27.7 | 27.7 | 27.7 | |||||
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable | 347.9 | 347.9 | 322.1 | |||||
Financing Activities (Textuals) [Abstract] | ||||||||
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition | 310 | 310 | 311 | |||||
Repayments of Long-term Debt | 1,899.3 | $ 784.1 | ||||||
Reacquired Pollution Controls Bonds Held by Trustees | 728 | $ 728 | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
Total Commitment from Bank Conduits to Finance Receivables | 750 | $ 750 | ||||||
Includes Debt Included In Liabilities Held For Sale [Member] | ||||||||
Long-term Debt | ||||||||
Senior Unsecured Notes | 14,761 | |||||||
Total Long-term Debt Outstanding | $ 19,551.9 | $ 19,551.9 | $ 20,391.2 | [5] | ||||
Commercial Paper [Member] | ||||||||
Short-term Debt: | ||||||||
Weighted Average Interest Rate | [4] | 1.43% | 1.43% | 1.02% | ||||
Loans Payable [Member] | ||||||||
Short-term Debt: | ||||||||
Weighted Average Interest Rate | [4] | 2.77% | 2.77% | 0.00% | ||||
AEP Subsidiaries [Member] | ||||||||
Long-term Debt | ||||||||
Long-term Debt Due Within One Year | $ 404.6 | $ 404.6 | $ 427.5 | |||||
Long-term Debt | 1,552.2 | 1,552.2 | 1,737.5 | |||||
AEP Transmission Co [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | 1,931.4 | 1,931.4 | 1,932 | |||||
Long-term Debt | 1,931.4 | 1,931.4 | 1,932 | |||||
Financing Activities (Textuals) [Abstract] | ||||||||
Sub-Limit of Secured Debt | $ 50 | $ 50 | ||||||
Maximum Percentage of Consolidated Tangible Net Assets | 10.00% | 10.00% | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
AEP Transmission Co [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 333.3 | |||||||
Maximum Loans to Money Pool | 52.9 | |||||||
Average Borrowings from Money Pool | 170.7 | |||||||
Average Loans to Money Pool | 12.3 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 246.3 | 246.3 | ||||||
Authorized Short Term Borrowing Limit | [6] | $ 795 | ||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.25% | 0.76% | ||||||
Average Interest Rate For Funds Loaned | 0.99% | 0.74% | ||||||
AEP Transmission Co [Member] | Direct Borrowing [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 1.1 | |||||||
Maximum Loans to Money Pool | 78.9 | |||||||
Average Borrowings from Money Pool | 1.1 | |||||||
Average Loans to Money Pool | 34.8 | |||||||
Borrowings from Parent | 1.1 | 1.1 | ||||||
Loans to Parent | 22.2 | 22.2 | ||||||
Authorized Short Term Borrowing Limit | $ 75 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate for Funds Borrowed | 1.44% | 0.84% | ||||||
Minimum Interest Rate For Funds Borrowed | 0.92% | 0.69% | ||||||
Maximum Interest Rate For Funds Loaned | 1.44% | 0.84% | ||||||
Minimum Interest Rate for Funds Loaned | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.18% | 0.75% | ||||||
Average Interest Rate For Funds Loaned | 1.21% | 0.75% | ||||||
Appalachian Power Co [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | 3,990.5 | $ 3,990.5 | 4,033.9 | |||||
Long-term Debt Due Within One Year | 149 | 149 | 503.1 | |||||
Long-term Debt | 3,841.5 | 3,841.5 | 3,530.8 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 365.9 | $ 136.5 | ||||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | 127.5 | 127.5 | 142 | |||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1.3 | 2 | 2.7 | 3.8 | ||||
Proceeds from Sale of Receivables | ||||||||
Proceeds from Sale of Receivables to AEP Credit | 324.2 | 325.5 | 693.9 | 709.9 | ||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | 365.9 | $ 136.5 | ||||||
Reacquired Pollution Controls Bonds Held by Trustees | 104 | $ 104 | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
Appalachian Power Co [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 231.5 | |||||||
Maximum Loans to Money Pool | 160.7 | |||||||
Average Borrowings from Money Pool | 179.1 | |||||||
Average Loans to Money Pool | 36.4 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 100.9 | 100.9 | ||||||
Authorized Short Term Borrowing Limit | $ 600 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.17% | 0.75% | ||||||
Average Interest Rate For Funds Loaned | 1.22% | 0.75% | ||||||
Appalachian Power Co [Member] | Pollution Control Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 104.4 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 104.4 | |||||||
Appalachian Power Co [Member] | Securitization Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 11.5 | |||||||
Interest Rate (Percentage) | 2.008% | 2.008% | ||||||
Due Date | 2,024 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 11.5 | |||||||
Appalachian Power Co [Member] | Senior Unsecured Notes [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 325 | ||||||
Interest Rate (Percentage) | 3.30% | 3.30% | ||||||
Due Date | 2,027 | |||||||
Appalachian Power Co [Member] | Senior Unsecured Notes Two [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 250 | |||||||
Interest Rate (Percentage) | 5.00% | 5.00% | ||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 250 | |||||||
Indiana Michigan Power Co [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | $ 2,691.4 | 2,691.4 | 2,471.4 | |||||
Long-term Debt Due Within One Year | 479.8 | 479.8 | 209.3 | |||||
Long-term Debt | 2,211.6 | 2,211.6 | 2,262.1 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 193.3 | $ 53.5 | ||||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | 145.6 | 145.6 | 136.7 | |||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1.6 | 1.7 | 3.1 | 3.6 | ||||
Proceeds from Sale of Receivables | ||||||||
Proceeds from Sale of Receivables to AEP Credit | 390.7 | 384.1 | 809 | 772.2 | ||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | 193.3 | $ 53.5 | ||||||
Reacquired Pollution Controls Bonds Held by Trustees | 50 | $ 50 | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
Indiana Michigan Power Co [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 367.4 | |||||||
Maximum Loans to Money Pool | 12.6 | |||||||
Average Borrowings from Money Pool | 258.6 | |||||||
Average Loans to Money Pool | 12.6 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 30.8 | 30.8 | ||||||
Authorized Short Term Borrowing Limit | $ 500 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.20% | 0.72% | ||||||
Average Interest Rate For Funds Loaned | 1.18% | 0.75% | ||||||
Indiana Michigan Power Co [Member] | Notes Payable, Other Payables [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 3.3 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 3.3 | |||||||
Indiana Michigan Power Co [Member] | Notes Payable Two [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 14.9 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,019 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 14.9 | |||||||
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 15.8 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,019 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 15.8 | |||||||
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Three [Member] | Subsequent Event [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 5 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | 5 | |||||||
Indiana Michigan Power Co [Member] | Notes Payable, Other Payable Four [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 15.9 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,020 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 15.9 | |||||||
Indiana Michigan Power Co [Member] | Notes Payable Five [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 15.7 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,021 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 15.7 | |||||||
Indiana Michigan Power Co [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 0.7 | |||||||
Interest Rate (Percentage) | 6.00% | 6.00% | ||||||
Due Date | 2,025 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 0.7 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 25 | ||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,019 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds Two [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 40 | ||||||
Interest Rate (Percentage) | 2.05% | 2.05% | ||||||
Due Date | 2,021 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds Three [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 52 | ||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,021 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds Four [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 25 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 25 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds Five [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 52 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 52 | |||||||
Indiana Michigan Power Co [Member] | Pollution Control Bonds Six [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 50 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,025 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 50 | |||||||
Indiana Michigan Power Co [Member] | Senior Unsecured Notes [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 300 | ||||||
Interest Rate (Percentage) | 3.75% | 3.75% | ||||||
Due Date | 2,047 | |||||||
Ohio Power Co [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | $ 1,742.5 | $ 1,742.5 | 1,763.9 | |||||
Long-term Debt Due Within One Year | 396.8 | 396.8 | 46.4 | |||||
Long-term Debt | 1,345.7 | 1,345.7 | 1,717.5 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 22.5 | $ 372.8 | ||||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | 322.4 | 322.4 | 388.3 | |||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 4.7 | 7.4 | 10.4 | 15.3 | ||||
Proceeds from Sale of Receivables | ||||||||
Proceeds from Sale of Receivables to AEP Credit | 493.1 | 613.7 | 1,125.4 | 1,260.3 | ||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | 22.5 | $ 372.8 | ||||||
Reacquired Pollution Controls Bonds Held by Trustees | 345 | 345 | ||||||
Ohio Power Co [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | 243.7 | |||||||
Maximum Loans to Money Pool | 56.2 | |||||||
Average Borrowings from Money Pool | 91.7 | |||||||
Average Loans to Money Pool | 27.9 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 190.5 | 190.5 | ||||||
Authorized Short Term Borrowing Limit | $ 400 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.31% | 0.79% | ||||||
Average Interest Rate For Funds Loaned | 0.98% | 0.74% | ||||||
Ohio Power Co [Member] | Securitization Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 22.5 | |||||||
Interest Rate (Percentage) | 0.958% | 0.958% | ||||||
Due Date | 2,018 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 22.5 | |||||||
Ohio Power Co [Member] | Securitization Bonds [Member] | Subsequent Event [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 24 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | 24 | |||||||
Public Service Co Of Oklahoma [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | $ 1,286.3 | 1,286.3 | 1,286 | |||||
Long-term Debt Due Within One Year | 0.5 | 0.5 | 0.5 | |||||
Long-term Debt | 1,285.8 | 1,285.8 | 1,285.5 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 0.2 | $ 0.2 | ||||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | 136.1 | 136.1 | 110.4 | |||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1.7 | 1.5 | 3.2 | 2.9 | ||||
Proceeds from Sale of Receivables | ||||||||
Proceeds from Sale of Receivables to AEP Credit | 328.7 | 309.2 | 615.5 | 581.3 | ||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 0.2 | $ 0.2 | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
Public Service Co Of Oklahoma [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 185.2 | |||||||
Maximum Loans to Money Pool | 0 | |||||||
Average Borrowings from Money Pool | 123.6 | |||||||
Average Loans to Money Pool | 0 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 141.4 | 141.4 | ||||||
Authorized Short Term Borrowing Limit | $ 300 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.23% | 0.76% | ||||||
Average Interest Rate For Funds Loaned | 0.00% | 0.73% | ||||||
Public Service Co Of Oklahoma [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 0.2 | |||||||
Interest Rate (Percentage) | 3.00% | 3.00% | ||||||
Due Date | 2,027 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 0.2 | |||||||
Southwestern Electric Power Co [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | $ 2,442.7 | 2,442.7 | 2,679.1 | |||||
Long-term Debt Due Within One Year | 385.4 | 385.4 | 353.7 | |||||
Long-term Debt | 2,057.3 | 2,057.3 | 2,325.4 | |||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 351.8 | $ 1.6 | ||||||
Short-term Debt: | ||||||||
Notes Payable | 8.7 | 8.7 | 0 | |||||
Accounts Receivable and Accrued Unbilled Revenues | ||||||||
Accounts Receivable and Accrued Unbilled Revenues | 163.5 | 163.5 | $ 130.9 | |||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | ||||||||
Fees Paid to AEP Credit for Customer Accounts Receivable Sold | 1.8 | 1.7 | 3.4 | 3.2 | ||||
Proceeds from Sale of Receivables | ||||||||
Proceeds from Sale of Receivables to AEP Credit | 404.6 | $ 387.4 | 745.8 | 723.5 | ||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 351.8 | $ 1.6 | ||||||
Maximum Percentage Debt to Capitalization | 67.50% | |||||||
Southwestern Electric Power Co [Member] | Utility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Borrowings from Money Pool | $ 187.5 | |||||||
Maximum Loans to Money Pool | 178.6 | |||||||
Average Borrowings from Money Pool | 132.4 | |||||||
Average Loans to Money Pool | 169.5 | |||||||
Net Loans (Borrowings) to/from Money Pool | 58.6 | 58.6 | ||||||
Authorized Short Term Borrowing Limit | $ 350 | |||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.92% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Borrowed | 1.20% | 0.75% | ||||||
Average Interest Rate For Funds Loaned | 0.98% | 0.00% | ||||||
Southwestern Electric Power Co [Member] | Nonutility [Member] | ||||||||
Money Pool Participants Money Pool Activity And Authorized Borrowing Limits [Abstract] | ||||||||
Maximum Loans to Money Pool | $ 2 | |||||||
Average Loans to Money Pool | 2 | |||||||
Net Loans (Borrowings) to/from Money Pool | $ 2 | $ 2 | ||||||
Maximum and Minimum Interest Rates | ||||||||
Maximum Interest Rate | 1.44% | 0.84% | ||||||
Minimum Interest Rate | 0.00% | 0.69% | ||||||
Average Interest Rates for Funds Borrowed From and Loaned to Money Pool [Abstract] | ||||||||
Average Interest Rate For Funds Loaned | 1.17% | 0.75% | ||||||
Southwestern Electric Power Co [Member] | Notes Payable, Other Payables [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 1.6 | |||||||
Interest Rate (Percentage) | 4.58% | 4.58% | ||||||
Due Date | 2,032 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 1.6 | |||||||
Southwestern Electric Power Co [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 115 | ||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,020 | |||||||
Southwestern Electric Power Co [Member] | OtherLongTermDebtTwo [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 100 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 100 | |||||||
Southwestern Electric Power Co [Member] | Other Long Term Debt Three [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 0.1 | |||||||
Interest Rate (Percentage) | 3.50% | 3.50% | ||||||
Due Date | 2,023 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 0.1 | |||||||
Southwestern Electric Power Co [Member] | Other Long Term Debt Four [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 0.1 | |||||||
Interest Rate (Percentage) | 4.28% | 4.28% | ||||||
Due Date | 2,023 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 0.1 | |||||||
Southwestern Electric Power Co [Member] | Senior Unsecured Notes [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 250 | |||||||
Interest Rate (Percentage) | 5.55% | 5.55% | ||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 250 | |||||||
Southwestern Electric Power Co [Member] | Loans Payable [Member] | ||||||||
Short-term Debt: | ||||||||
Weighted Average Interest Rate | [4] | 2.77% | 2.77% | 0.00% | ||||
AEP Generating Co [Member] | Senior Unsecured Notes [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 152.7 | |||||||
Interest Rate (Percentage) | 6.33% | 6.33% | ||||||
Due Date | 2,037 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 152.7 | |||||||
AEP Texas Central Co [Member] | Securitization Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 27.2 | |||||||
Interest Rate (Percentage) | 0.88% | 0.88% | ||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 27.2 | |||||||
AEP Texas Central Co [Member] | Securitization Bonds [Member] | Subsequent Event [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | 71 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 71 | |||||||
AEP Texas Central Co [Member] | Securitization Bonds Two [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 89.9 | |||||||
Interest Rate (Percentage) | 5.17% | 5.17% | ||||||
Due Date | 2,018 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 89.9 | |||||||
Kentucky Power Co [Member] | Pollution Control Bonds [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 65 | ||||||
Interest Rate (Percentage) | 2.00% | 2.00% | ||||||
Due Date | 2,020 | |||||||
Kentucky Power Co [Member] | Pollution Control Bonds Two [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 65 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 65 | |||||||
AEP Generation Resources [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 500 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,017 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 500 | |||||||
Transource Missouri [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 7 | ||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,018 | |||||||
Transource Missouri [Member] | OtherLongTermDebtTwo [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Retirements and Principal Payments | $ 130.8 | |||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,018 | |||||||
Financing Activities (Textuals) [Abstract] | ||||||||
Repayments of Long-term Debt | $ 130.8 | |||||||
Transource Energy [Member] | Other Long Term Debt [Member] | ||||||||
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made | ||||||||
Issuances | [2] | $ 132.1 | ||||||
Interest Rate (Variable) | Variable | |||||||
Due Date | 2,020 | |||||||
Includes Debt Included In Liabilities Held For Sale [Member] | ||||||||
Long-term Debt | ||||||||
Total Long-term Debt Outstanding | [1] | $ 20,391.2 | ||||||
Long-term Debt Due Within One Year | [1] | 3,013.4 | ||||||
Long-term Debt | [1] | $ 17,377.8 | ||||||
[1] | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 6 for additional information. | |||||||
[2] | 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. | |||||||
[3] | Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. | |||||||
[4] | Weighted average rate. | |||||||
[5] | Amounts include debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See the Assets and Liabilities Held for Sale section of Note 6 for additional information. | |||||||
[6] | Amount represents the combined authorized short-term borrowing limit the State Transcos have through their agreements with the FERC or state regulatory commissions. |